FINANCIAL REVIEW AT DECEMBER 31, 2015

Transcription

1 INNERGEX RENEWABLE ENERGY INC. FINANCIAL REVIEW AT DECEMBER 31, 2015 TABLE OF CONTENTS Management s Discussion and Analysis 2 Responsibility for Financial Reporting 65 Independent Auditor s Report 66 Consolidated Financial Statements 67 Notes to the Consolidated Financial Statements 75 Information for Investors 142

2 Innergex Renewable Energy Inc. is a leading Canadian independent renewable power producer. Active since 1990, the Corporation develops, owns and operates run-of-river hydroelectric facilities, wind farms, and solar photovoltaic farms and carries out its operations in Quebec, Ontario and British Columbia, and in Idaho, USA. The Corporation s shares are listed on the Toronto Stock Exchange under the symbols INE, INE.PR.A and INE.PR.C and its convertible debentures are listed under the symbol INE.DB.A. Innergex s mission is to increase its production of renewable energy by developing and operating high-quality facilities while respecting the environment and balancing the best interests of the host communities, its partners and its investors.f 2015 HIGHLIGHTS The Corporation closed $1,000.5 million of project financing. It completed project financing for the Boulder Creek, Upper Lillooet River and Big Silver Creek hydroelectric projects in British Columbia, for a total of $688.8 million. It also closed project financing of $311.7 million for the Mesgi g Ugju s n wind project located in Quebec. The Corporation reviewed the total anticipated project costs to achieve the completion of the Tretheway Creek project and the three projects under construction. Savings of $36.0 million are expected over the previously estimated total project costs. Construction began at the Mesgi g Ugju s n wind project in Quebec. The Mesgi g Ugju s n project is a 150 MW wind project jointly owned by the three Mi gmaq First Nations of Quebec, namely the Gesgapegiag, Gespeg and Listuguj nations, and by Innergex. The Corporation issued $100.0 million of convertible debentures bearing interest at 4.25% and redeemed $41.6 million and converted $38.0 million of an outstanding principal of $80.5 million of convertible debentures bearing interest at 5.75%. Innergex and the Cayoose Creek Band signed an agreement for the joint acquisition of the Walden North Hydroelectric project in British Columbia for $9.2 million. The acquisition was closed on February 25, The Corporation signed a memorandum of understanding with the Comisión Federal de Electricidad ( CFE ) to jointly study a number of renewable energy project opportunities in Mexico with the aim of jointly developing selected projects. A s at December 31, 2015, the Corporation had purchased for cancellation 1,190,173 common shares at an average price of $10.36, under its normal course issuer bid FINANCIAL PERFORMANCE Electricity production increased 1% to 2,987 GWh and was 98% of the long-term average Revenues rose 2% to $246.9 million compared with last year Adjusted EBITDA rose 2% to $183.7 million compared with last year Free Cash Flow generated reached $74.4 M Payout ratio improved to 86% compared with 88% last year On February 24, 2016, the Board of Directors announced an increase in the annual dividend that the Corporation intends to distribute to common shareholders. This annual increase of $0.02 to $0.64 per common share, payable quarterly, reflects the execution of the Corporation s strategy for building shareholder value, which is to develop or acquire high-quality renewable power production facilities that generate sustainable cash flows and provide an attractive risk-adjusted return on invested capital, and to distribute a stable dividend.f REVENUES AND ADJUSTED EBITDA At December 31 ($000s) NET INSTALLED CAPACITY At December 31 (MW) , , , , , , , ,792 Revenues , ,196 Adjusted EBITDA 1 Prepared in accordance with IFRS excluding joint ventures. 2 Including joint ventures

3 MANAGEMENT'S DISCUSSION AND ANALYSIS INTRODUCTION This Management's Discussion and Analysis ( MD&A ) is a discussion of the operating results, cash flows and financial position of Innergex Renewable Energy Inc. ( Innergex or the Corporation ) for the year ended December 31, 2015, and reflects all material events up to February 24, 2016, the date on which this MD&A was approved by the Corporation's Board of Directors. The MD&A should be read in conjunction with the audited consolidated financial statements and the accompanying notes for the year ended December 31, The audited consolidated financial statements attached to this MD&A and the accompanying notes for the year ended December 31, 2015, along with the 2014 comparative figures, have been prepared in accordance with International Financial Reporting Standards ( IFRS ). Some amounts included in this MD&A have been rounded to make reading easier, which may affect some calculations. TABLE OF CONTENTS Establishment and Maintenance of DC&P and ICFR... 2 Financial Position Forward-Looking Information... 3 Transaction between Related Parties Non-IFRS Measures... 5 Free Cash Flow and Payout Ratio Additional Information and Updates... 6 Projected Financial Performance Overview... 6 Outlook for Business Strategy... 8 Segment Information Market Trends Quarterly Financial Information Selected Annual Information Fourth quarter Results Commissioning Activities Investments in Joint Ventures Developments in Non-Wholly Owned Subsidiaries Development Projects Risks and Uncertainties Prospective Projects Critical Accounting Estimates Operating Results Accounting Changes Liquidity and Capital Resources Subsequent Events Dividends ESTABLISHMENT AND MAINTENANCE OF DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING The President and Chief Executive Officer and the Chief Financial Officer of the Corporation have designed, or caused to be designed, under their supervision: Disclosure controls and procedures ( DC&P ) to provide reasonable assurance that: (i) material information relating to the Corporation is accumulated and communicated by others to the President and Chief Executive Officer and the Chief Financial Officer in a timely manner, particularly during the period in which the interim and annual filings are being prepared; and (ii) the information required to be disclosed by the Corporation in its annual filings, interim filings and other reports filed or submitted by it under applicable securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation. Internal control over financial reporting ( ICFR ) to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS applicable to the Corporation. In accordance with Regulation Certification of Disclosure in Issuers' Annual and Interim Filings, the President and Chief Executive Officer and the Chief Financial Officer of the Corporation have evaluated the effectiveness of the Corporation's DC&P and ICFR as at December 31, 2015, and have concluded that they were effective and that there were no material weaknesses relating to the DC&P and ICFR for the year ended December 31, During the year ended December 31, 2015 there was no change to the ICFR that has materially affected, or is reasonably likely to materially affect, the Corporation's ICFR. Innergex Renewable Energy Inc Financial Review - 2

4 MANAGEMENT'S DISCUSSION AND ANALYSIS FORWARD-LOOKING INFORMATION To inform readers of the Corporation's future prospects, this MD&A contains forward-looking information within the meaning of applicable securities laws ( Forward-Looking Information ). Forward-Looking Information can generally be identified by the use of words such as approximately, may, will, "could", believes", expects", intends, "should", plans, potential, "project", anticipates, estimates, scheduled or forecasts, or other comparable terminology that state that certain events will or will not occur. It represents the projections and expectations of the Corporation relating to future events or results as of the date of this MD&A. Future-oriented financial information: Forward-Looking Information includes future-oriented financial information or financial outlook within the meaning of securities laws, such as expected production, projected revenues, projected Adjusted EBITDA, projected Free Cash Flow, estimated project costs and expected project financing, to inform readers of the potential financial impact of expected results, of the expected commissioning of Development Projects, of the Corporation's ability to sustain current dividends and dividend increases and of its ability to fund its growth. Such information may not be appropriate for other purposes. Assumptions: Forward-Looking Information is based on certain key assumptions made by the Corporation, including those concerning hydrology, wind regimes and solar irradiation, performance of operating facilities, financial market conditions and the Corporation s success in developing new facilities. Risks and uncertainties: Forward-Looking Information involves risks and uncertainties that may cause actual results or performance to be materially different from those expressed, implied or presented by the Forward-Looking Information. These are referred to in the Corporation s Annual Information Form in the Risk Factors section and include, without limitation: the ability of the Corporation to execute its strategy for building shareholder value; its ability to raise additional capital and the state of capital markets; liquidity risks related to derivative financial instruments; variability in hydrology, wind regimes and solar irradiation; delays and cost overruns in the design and construction of projects; health, safety and environmental risks; uncertainties surrounding the development of new facilities; obtainment of permits; variability of installation performance and related penalties; equipment failure or unexpected operations and maintenance activity; interest rate fluctuations and refinancing risk; financial leverage and restrictive covenants governing current and future indebtedness; the possibility that the Corporation may not declare or pay a dividend; the ability to secure new power purchase agreements or to renew any power purchase agreement; changes in governmental support to increase electricity to be generated from renewable sources by independent power producers; the ability to attract new talent or to retain officers or key employees; litigation; performance of major counterparties; social acceptance of renewable energy projects; relationships with stakeholders; equipment supply; changes in general economic conditions; regulatory and political risks; the ability to secure appropriate land; reliance on power purchase agreements; availability and reliability of transmission systems; increases in water rental cost or changes to regulations applicable to water use; assessment of water, wind and sun resources and associated electricity production; dam failure; natural disasters and force majeure; foreign exchange fluctuations; foreign market growth and development risks; cybersecurity; sufficiency of insurance coverage limits and exclusions; a credit rating that may not reflect actual performance of the Corporation or a lowering (downgrade) of the credit rating; potential undisclosed liabilities associated with acquisitions; integration of the facilities and projects acquired and to be acquired; failure to realize the anticipated benefits of acquisitions; reliance on shared transmission and interconnection infrastructure; and the fact that revenues from the Miller Creek facility will vary based on the spot price of electricity. Although the Corporation believes that the expectations and assumptions on which Forward-Looking Information is based are reasonable under the current circumstances, readers are cautioned not to rely unduly on this Forward-Looking Information as no assurance can be given that it will prove to be correct. Forward-Looking Information contained herein is made as at the date of this MD&A and the Corporation does not undertake any obligation to update or revise any Forward-Looking Information, whether as a result of events or circumstances occurring after the date hereof, unless so required by law. Forward-Looking Information in this MD&A The following table outlines the Forward-Looking Information contained in this MD&A, which the Corporation considers important to better inform readers about its potential financial performance, together with the principal assumptions used to derive this information and the principal risks and uncertainties that could cause actual results to differ materially from this information. Innergex Renewable Energy Inc Financial Review - 3

5 MANAGEMENT'S DISCUSSION AND ANALYSIS Principal Assumptions Expected production For each facility, the Corporation determines a long-term average annual level of electricity production ("LTA") over the expected life of the facility, based on engineers studies that take into consideration a number of important factors: for hydroelectricity, the historically observed flows of the river, the operating head, the technology employed and the reserved aesthetic and ecological flows; for wind energy, the historical wind and meteorological conditions and turbine technology; and for solar energy, the historical solar irradiation conditions, panel technology and expected solar panel degradation. Other factors taken into account include, without limitation, site topography, installed capacity, energy losses, operational features and maintenance. Although production will fluctuate from year to year, over an extended period it should approach the estimated long-term average. On a consolidated basis, the Corporation estimates the LTA by adding together the expected LTA of all the facilities in operation that it consolidates (excludes Umbata Falls and Viger-Denonville, which are accounted for using the equity method). Principal Risks and Uncertainties Improper assessment of water, wind and sun resources and associated electricity production Variability in hydrology, wind regimes and solar irradiation Equipment failure or unexpected operations and maintenance activity Natural disaster Projected revenues For each facility, expected annual revenues are estimated by multiplying the LTA by a price for electricity stipulated in the power purchase agreement secured with a public utility or other creditworthy counterparty. These agreements stipulate a base price and, in some cases, a price adjustment depending on the month, day and hour of delivery, except for the Miller Creek hydroelectric facility, which receives a price based on a formula using the Platts Mid- C pricing indices, and the Horseshoe Bend hydroelectric facility, for which 85% of the price is fixed and 15% is adjusted annually as determined by the Idaho Public Utility Commission. In most cases, power purchase agreements also contain an annual inflation adjustment based on a portion of the Consumer Price Index. On a consolidated basis, the Corporation estimates annual revenues by adding together the projected revenues of all the facilities in operation that it consolidates (excludes Umbata Falls and Viger-Denonville, which are accounted for using the equity method). Production levels below the LTA caused mainly by the risks and uncertainties mentioned above Unexpected seasonal variability in the production and delivery of electricity Lower-than-expected inflation rate Projected Adjusted EBITDA For each facility, the Corporation estimates annual operating earnings by subtracting from the estimated revenues the budgeted annual operating costs, which consist primarily of operators salaries, insurance premiums, operations and maintenance expenditures, property taxes and royalties; these are predictable and relatively fixed, varying mainly with inflation (except for maintenance expenditures). On a consolidated basis, the Company estimates annual Adjusted EBITDA by adding together the projected operating earnings of all the facilities in operation that it consolidates (which excludes Umbata Falls and Viger-Denonville, accounted for using the equity method), from which it subtracts budgeted general and administrative expenses, comprised essentially of salaries and office expenses, and budgeted prospective project expenses, which are determined based on the number of prospective projects the Corporation chooses to develop and the resources required to do so. Variability of facility performance and related penalties Changes to water and land rental expenses Unexpected maintenance expenditures Changes in the purchase price of electricity upon renewal of a PPA Estimated project costs, expected obtainment of permits, start of construction, work conducted and start of commercial operation for Development Projects or Prospective Projects For each development project, the Corporation provides an estimate of project costs based on its extensive experience as a developer, directly related incremental internal costs, site acquisition costs and financing costs, which are eventually adjusted for the projected costs provided by the engineering, procurement and construction ("EPC") contractor retained for the project. The Corporation provides indications regarding scheduling and construction progress for its Development Projects and indications regarding its Prospective Projects, based on its extensive experience as a developer. Performance of counterparties, such as the EPC contractors Delays and cost overruns in the design and construction of projects Obtainment of permits Equipment supply Interest rate fluctuations and financing risk Relationships with stakeholders Regulatory and political risks Higher-than-expected inflation Natural disaster Innergex Renewable Energy Inc Financial Review - 4

6 MANAGEMENT'S DISCUSSION AND ANALYSIS Principal Assumptions Projected Free Cash Flow The Corporation estimates Free Cash Flow as projected cash flow from operations before changes in non-cash operating working capital items, less estimated maintenance capital expenditures net of proceeds from disposals, scheduled debt principal payments, preferred share dividends and the portion of Free Cash Flow attributed to non-controlling interests, plus cash receipts by the Harrison Hydro L.P. for the wheeling services to be provided to other facilities owned by the Corporation over the course of their power purchase agreement. It also adjusts for other elements, which represent cash inflows or outflows that are not representative of the Corporation's long-term cash generating capacity, such as adding back transaction costs related to realized acquisitions (which are financed at the time of the acquisition) and adding back realized losses or subtracting realized gains on derivative financial instruments used to fix the interest rate on project-level debt or the exchange rate on equipment purchases. Intention to submit projects under requests for proposals The Corporation provides indications of its intention to submit projects under requests for proposals based on the state of readiness of some of its Prospective Projects and their compatibility with the announced terms of these requests for proposals. Intention to gain a foothold in target markets internationally The Corporation provides indications of its intention to establish a presence in target markets internationally in the coming years, based on its growth strategy. Principal Risks and Uncertainties Adjusted EBITDA below expectations caused mainly by the risks and uncertainties mentioned above and by higher prospective project expenses Projects costs above expectations caused mainly by the performance of counterparties and delays and cost overruns in the design and construction of projects Regulatory and political risk Interest rate fluctuations and financing risk Financial leverage and restrictive covenants governing current and future indebtedness Unexpected maintenance capital expenditures Regulatory and political risks Ability of the Corporation to execute its strategy for building shareholder value Ability to secure new PPAs Regulatory and political risks Ability of the Corporation to execute its strategy for building shareholder value Ability to secure new PPAs Foreign exchange fluctuations NON IFRS MEASURES This MD&A has been prepared in accordance with International Financial Reporting Standards ( IFRS ). However, some measures referred to in this MD&A are not recognized measures under IFRS and therefore may not be comparable to those presented by other issuers. Innergex believes that these indicators are important, as they provide management and the reader with additional information about the Corporation's production and cash generation capabilities, its ability to sustain current dividends and dividend increases and its ability to fund its growth. These indicators also facilitate the comparison of results over different periods. Adjusted EBITDA, Free Cash Flow and Payout Ratio are not measures recognized by IFRS and have no standardized meaning prescribed by IFRS. References in this document to Adjusted EBITDA are to revenues less operating expenses, general and administrative expenses and prospective project expenses. References to Free Cash Flow are to cash flows from operating activities before changes in non-cash operating working capital items, less maintenance capital expenditures net of proceeds from disposals, scheduled debt principal payments, preferred share dividends declared and the portion of Free Cash Flow attributed to non-controlling interests, plus cash receipts by the Harrison Hydro Limited Partnership for the wheeling services to be provided to other facilities owned by the Corporation over the course of their PPA, plus or minus other elements that are not representative of the Corporation's long-term cash generating capacity, such as transaction costs related to realized acquisitions (which are financed at the time of the acquisition) and realized losses or gains on derivative financial instruments used to hedge the interest rate on project-level debt or the exchange rate on equipment purchases. References to Payout Ratio are to dividends declared on common shares divided by Free Cash Flow. Readers are cautioned that Adjusted EBITDA should not be construed as an alternative to net earnings and Free Cash Flow should not be construed as an alternative to cash flows from operating activities, as determined in accordance with IFRS. Innergex Renewable Energy Inc Financial Review - 5

7 MANAGEMENT'S DISCUSSION AND ANALYSIS ADDITIONAL INFORMATION AND UPDATES Additional information relating to Innergex, including its Annual Information Form, can be found on the Canadian Securities Administrators' System for Electronic Document Analysis and Retrieval ( SEDAR ) at or on the Corporation's website at Information contained in or otherwise accessible through our website does not form part of this MD&A and is not incorporated into the MD&A by reference. OVERVIEW The Corporation is a developer, owner and operator of renewable power-generating facilities with a focus on hydroelectric, wind power and solar photovoltaic ( PV ) projects that benefit from low operating and management costs and simple, proven technologies. Portfolio of Assets As at the date of this MD&A, the Corporation owns interests in three groups of power-generating projects: 34 facilities in commercial operation (the Operating Facilities ). Commissioned between November 1994 and October 2015, the facilities have a weighted average age of approximately 8.1 years. They sell the generated power under long-term Power Purchase Agreements ( PPA ) that have a weighted average remaining life of 18.1 years (based on gross long-term average production); Two projects scheduled to begin commercial operation by the end of 2016 and two projects scheduled to start commercial operations in the first and second quarter of 2017 (all together the Development Projects ). Construction is ongoing at all four of these projects; Numerous projects that have secured land rights, for which an investigative permit application has been filed or for which a proposal has either been or could be submitted under a Request for Proposal or a Standing Offer Program (collectively the Prospective Projects ). These projects are at various stages of development. The following chart diagrams the Corporation's direct and indirect interests in the Operating Facilities, Development Projects and Prospective Projects. Innergex Renewable Energy Inc Financial Review - 6

8 MANAGEMENT'S DISCUSSION AND ANALYSIS Innergex Renewable Energy Inc Financial Review - 7

9 MANAGEMENT'S DISCUSSION AND ANALYSIS BUSINESS STRATEGY The Corporation's strategy for building shareholder value is to develop or acquire high-quality renewable power production facilities that generate sustainable cash flows and provide an attractive risk-adjusted return on invested capital and to distribute a stable dividend. Produce Only Renewable Energy The Corporation is committed to producing electricity exclusively from renewable energy sources. Develop Sustainably In conducting its business, the Corporation strives to achieve a balance between economic, social and environmental considerations and is committed to planning, deciding, managing, and operating through the lens of sustainability. Maintain Diversification of Energy Sources The amount of electricity generated by the Operating Facilities is generally dependent on the availability of water flows, wind regimes and solar irradiation. Lower-than-expected water flows, wind regimes or solar irradiation in any given year could have an impact on the Corporation's revenues and hence on its profitability. Innergex owns interests in 27 hydroelectric facilities, which draw on 24 watersheds, 6 wind farms and 1 solar farm, providing significant diversification in terms of operating revenue sources. Furthermore, the nature of hydroelectric, wind and solar power generation partially offsets any seasonal variations, as illustrated in the following table and charts: Consolidated long-term average production 1 In GWh and % Q1 Q2 Q3 Q4 Total HYDRO % % % % 2,415.9 WIND % % % % SOLAR % % % % 37.9 Total % 1, % % % 3, Annualized long-term average production ("LTA") for the facilities in operation at February 24, The LTA is presented in accordance with revenue recognition accounting rules under IFRS and excludes production from facilities that are accounted for using the equity method, which is presented in the "Investments in Joint Ventures" section. 2. Solar farm LTA diminishes over time due to expected solar panel degradation. Innergex Renewable Energy Inc Financial Review - 8

10 MANAGEMENT'S DISCUSSION AND ANALYSIS Develop Strategic Relationships Strategic relationships and partnerships are an important component of the Corporation's business strategy. When the Corporation teams up with a strategic or financial partner, the Corporation and the partner share ownership of the projects concerned. Current strategic partners include TransCanada Energy Ltd. (owner of 62% of the Baie-des-Sables, L'Anse-à- Valleau, Carleton, Montagne Sèche and Gros-Morne wind farms), the Ojibways of the Pic River First Nations (owner of 51% of the Umbata Falls facility), the Kanaka Bar Indian Band (owner of 50% of the Kwoiek Creek facility), the Rivière-du-Loup Regional County Municipality (owner of 50% of the Viger-Denonville community wind farm), Ledcor Power Group Ltd. (owner of 33 1 / 3 % of the Fitzsimmons Creek facility, the Boulder Creek and Upper Lillooet River Development Projects as well as other Creek Power Inc. Prospective Projects), the Mi'gmawei Mawiomi (or the Mi'gmaq First Nations of Quebec) (owner of 50% of the Mesgi'g Ugju's'n wind Development Project) and the Minganie Regional County Municipality (owner of 0.001% of the common units and 30% of the voting units of the Magpie hydroelectric facility). Current financial partners include CC&L Harrison Hydro Project Limited Partnership and LPF (Surfside) Development L.P. (owners of 34.99% and 15.00% of Harrison Hydro Limited Partnership respectively) as well as the Desjardins Group Pension Plan (owner of 49.99% of the SM-1 hydroelectric facility). Pursue Opportunities for Renewable Energy Growth Growing awareness and concern over issues such as climate change, access to clean energy, energy security, energy efficiency and the environmental impacts of conventional fossil fuels are leading governments around the world to increase their demand for and commitments to the development of renewable energy supply. Consequently, the Corporation believes that the outlook for the renewable energy industry is promising. Key Growth Factors The Corporation's future growth will be affected by the following key factors: Demand for renewable energy; Stable and long-term government policies for the procurement of new renewable energy capacity, whether through requests for proposals or other mechanisms; Its capacity to evaluate and secure the best prospective sites for the development of new projects in cooperation with local communities; Its ability to enter into attractive PPAs and obtain the required environmental and other permits; Its ability to adequately forecast total construction costs, expected revenues and expected expenses for each project; Its ability to make accretive acquisitions; and Its ability to finance its growth. Key Geographic Markets On December 21, 2015, the Quebec government, in collaboration with Hydro-Québec, announced the issuance of a 200 MW block of wind energy to the Innu First Nation in the province's Côte-Nord region and the Corporation plans to seek opportunities in relation thereto. The Corporation remains confident in the long-term viability of the small hydro and wind energy sectors in this province and has a number of projects that it continues to advance for future renewable energy procurement opportunities. Furthermore, the prices of the recent request for proposals demonstrate the competitiveness of renewable energy in Quebec, even in the context of weak fossil fuel prices and large hydroelectric dam procurement capabilities. In Ontario, the government has instituted a competitive procurement process, the Large Renewable Procurement ("LRP") that will take into account local needs and considerations, including those of municipalities and First Nations. The LRP is currently underway with procurement targets of 300 MW of wind energy, 140 MW of solar energy, 75MW for water power, and 50MW for bioenergy. The LRP II procurement process, which is expected to begin in late 2016, may procure up to 300 MW of wind energy and 150 MW of solar energy, with planned annual revisions thereafter. The Corporation has a number of wind and solar projects that it continues to advance in preparation for submissions under these competitive bid processes. In 2015, the Corporation submitted bids for one solar project and one wind project, both in partnership with a First Nations partner, and is awaiting response from the governing authorities in Q Other prospective projects in Ontario, especially in the wind sector, remain predicated on both the transmission grid expansion in the northern part of the province and decisions regarding nuclear refurbishment to represent longer-term growth potential. In British Columbia, while the government has stated its support for a healthy, diverse clean energy sector and clean energy opportunities for First Nations, it has provided no specific procurement targets for renewable energy at this time beyond the Innergex Renewable Energy Inc Financial Review - 9

11 MANAGEMENT'S DISCUSSION AND ANALYSIS Standing Offer Program (150 GWH/year). Furthermore, the province is currently experiencing decreasing demand for electricity over the short term, although the longer term forecast is for an increase. While plans remain to develop its mining and liquefied natural gas ( LNG ) sectors, they have been delayed due to the current global economy. Construction has commenced on BC Hydro's 1,100 MW Site-C hydroelectric dam project, which is scheduled to reach commercial operation in 2024 and which may reduce some prospects for independent power producers. Site-C is a component of BC Hydro's Integrated Resource Plan (IRP), which was approved by the BC government in November 2013 and is now scheduled to be updated in 2016, once the province has announced its Climate Leadership Plan. The IRP is a flexible long-term strategic plan to meet this province's growth in electricity demand over the next 20 years. In the United States, the Corporation will continue to selectively assess potential opportunities, particularly in light of the current U.S. administration's focus on addressing climate change and reducing GHG emissions as well as the existence of renewable portfolio standards in several states and the increasing procurement of renewable energy. According to the US Energy Information Association (EIA), electricity generation from renewable energy is expected to rise from 12% in 2012 to 16% by In the short term, generation from renewable resources is expected to grow in response to federal tax credits and statelevel policies. However, in the long term, renewable generation growth is expected to be driven by increasing cost competitiveness with other non-renewable technologies. In many markets across the US, wind and solar energy are already among the least costly new generation sources, even compared with currently low-cost natural gas. To replenish its sources of long-term growth, the Corporation has identified a number of target markets internationally in which it expects to gain a foothold in the coming years. In developing economies in Latin America, demand for electricity remains strong and governments are seeking to increase the production of renewable energy, of which they have an ample supply. More economically mature countries in Europe have adopted ambitious GHG emissions reduction targets and governments are seeking to reduce their dependency on conventional forms of generation, both of which developments require a greater proportion of renewable energy in these countries' energy portfolios. There are a number of markets to which the Corporation believes it can largely transpose its business model for developing and operating renewable energy assets. In Mexico, the Corporation announced on October 13, 2015, that it had signed a memorandum of understanding with the Comisión Federal de Electricidad (CFE), a productive government enterprise that produces and distributes electricity to more than 38.5 million customers representing 120 million Mexicans, to jointly study a number of renewable energy project opportunities in Mexico with the aim of jointly developing selected projects. The main purpose of the agreement is to coordinate efforts and develop activities that will allow Innergex and CFE to define their joint participation in the development of prospective renewable energy projects, in particular small hydroelectric plants of less than 200 MW. Over the past two years, the Mexican government has undertaken vast reforms of its electricity market, opening it to private power producers. The government has implemented ambitious targets to increase capacity to meet the rapidly growing demand for electricity, while also transitioning from fossil fuel to renewable energy generation in order to achieve greenhouse gas emission reduction targets. As the country s largest electricity producer, CFE is looking to make significant investments in order to meet the annual renewable energy quotas. On November 30, 2015, Mexico s National Energy Control Center ("CENACE") released the tender rules ("Tender Rules") for participating in Mexico's First Long-Term Energy Auction (the "Auction"). The purpose of the Auction is to award Electricity Coverage Agreements on behalf of the CFE for the acquisition of Electric Power, Accruable Electric Energy and Clean Energy Certificates. In France, the Corporation is actively assessing a number of renewable energy opportunities and hopes to establish its presence during the course of Since 2007, France has put in place an ambitious strategy for the development of renewable energies within its territory. France's energy policy emphasizes the implementation of renewable energies with a targeted additional production of 20 megatonnes of oil equivalent (Mtoe) compared with 2006,or an approximate doubling in production of renewable energies by Pursue Growth Opportunities Through Acquisitions Acquisitions are another important component of the Corporation's business strategy. More specifically, the Corporation will seek acquisitions that will enable it to gain a foothold and develop a critical mass in identified target markets internationally. It will also seek acquisitions in order to consolidate its leadership position in the Canadian renewable energy industry. As it has done in the past, Innergex will continue to focus on hydroelectric, wind and solar power generation assets. The Corporation could also grow through expansion into other forms of renewable energy production if profitable opportunities arise. Innergex Renewable Energy Inc Financial Review - 10

12 MANAGEMENT'S DISCUSSION AND ANALYSIS Maintain Capacity for Delivering Results The Corporation does business in a competitive sector. The experience and dedication of its management team constitute its strongest asset. Through careful management, it has established a track record of completing projects by the commercial operation start date specified in their PPA while adhering to the established construction budgets. The Corporation's employees possess the specialized knowledge and skills necessary to carry out its business. The Corporation can also rely on a network of technical, financial and legal partners and has proved its ability to complement its internal capabilities with efficient use of external consultants when required. In addition, the Corporation retains the services of several engineering firms to assist with the feasibility analysis of its projects. As at December 31, 2015, the Corporation employed a total of 188 persons (including Cartier Wind Energy employees). Use Key Performance Indicators The Corporation measures its performance using key performance indicators that include or could include comparing power generated in megawatt-hours ( MWh ) and gigawatt-hours ( GWh ) with a long-term average, Adjusted EBITDA and Adjusted EBITDA Margin, Free Cash Flow and Payout Ratio. These indicators are not recognized measures under IFRS, have no standardized meaning prescribed by IFRS and therefore may not be comparable with those presented by other issuers. The Corporation believes that these indicators are important, as they provide management and the reader with additional information about the Corporation's production and cash generating capabilities, its ability to sustain current dividends and dividend increases and its ability to fund its growth. These indicators also facilitate the comparison of results over different periods. Please refer to the "Non-IFRS Measures" section for more information. Dividend Policy The Corporation intends to distribute an annual dividend of $0.64 per common share, payable quarterly. The Corporation s dividend policy is determined by its Board of Directors and is based on the Corporation s operating results, cash flows, financial condition, debt covenants, long-term growth prospects, solvency tests imposed under corporate law for the declaration of dividends and other relevant factors. MARKET TRENDS Renewable power producers are involved in the generation of electricity from renewable energy sources including hydro, wind, solar, landfill gas and geothermal sources. While traditional regulated utilities continue to dominate North American electricity generation markets, the growing importance of the role played by independent power producers in meeting future electricity needs is now acknowledged and the benefits of their power output have increasingly been recognized by government authorities and policymakers in recent years. There are several factors that explain the growing role played by independent power producers in supplying renewable power in North America, including: the growing demand for energy; increasing awareness of the benefits of renewable energy in addressing the impacts of climate change; the increase in government-sponsored incentives to develop renewable energy capacity; the availability of long-term renewable energy purchase contracts with highly creditworthy counterparties, allowing independent power producers to develop new projects in a low-risk environment with the expectation of stable long-term contractual cash flows; the implementation of non-discriminatory access to transmission systems, providing independent power producers with access to regional electricity markets; and the rapidly improving cost-competitiveness of renewable energy and efficiency of independent power producers. While the plentiful supply of natural gas in recent years has resulted in low market prices that have increased the attractiveness of this source of energy for producing electricity in many parts of the world, technological improvements and economies of scale have significantly reduced the costs of renewable energy procurement, in particular wind and solar power. In many markets, electricity produced from these sources is cost-competitive with energy produced from natural gas and its cost is much more stable over the long run because it is not subject to fluctuations in the price of the underlying resource year over year. Innergex Renewable Energy Inc Financial Review - 11

13 MANAGEMENT'S DISCUSSION AND ANALYSIS Over and above the foregoing, a significant push for developing renewable energy worldwide and implementing a global energy transition toward clean and renewable energy came during the 21st Conference of Parties, which was held in Paris, France from November 30 to December 11, According to the United Nations Environmental Program, the international political response to climate change began at the Rio Earth Summit in 1992, where the "Rio Convention" included the adoption of the UN Framework on Climate Change. This convention set out a framework for action aimed at stabilizing atmospheric concentrations of greenhouse gases to avoid dangerous anthropogenic interference with the climate system. The 2015 Paris Climate Conference was one of the largest international conferences ever held in the country and attracted close to 50,000 participants, including 25,000 official delegates from government, intergovernmental organizations, UN agencies, NGOs and civil society. The agreement that came out of the 2015 Paris Climate Conference (the "Paris Agreement") is a legally binding, universal agreement on climate, with the aim of keeping global warming well below 2 C. The Paris Agreement establishes longterm vision in order to greatly reduce global emissions and phase out carbon from the world's energy sources through an ambitions deployment of and important transition to renewable energy within each national energy strategy. Renewable Power in Canada Over the past few years, the significant growth in renewable power generation in Canada has resulted from: rising electricity and fossil fuel prices; the increased cost of large-scale hydroelectric sites; public concern over nuclear power generation, air quality, and greenhouse gases; improvements in renewable energy technologies; and shorter construction lead times for some renewable energy projects. Renewable electricity generation in Canada is also supported by federal and provincial incentives, such as long-term fixed price contracts, accelerated depreciation and Renewable Portfolio Standards, which are explained below. In response to the long-term trend toward stronger environmental protection policies, many provincial governments have introduced Renewable Portfolio Standards ( RPS ), which typically set a target for an increased component of renewable energy in their electricity generation supply mix in order to reduce greenhouse gas emissions over time. These RPS typically reflect the distinct resource issues associated with electricity generation, given the provinces' respective electricity industry structures and geographical conditions. While RPS are sometimes applied and implemented as goals or targets rather than mandatory requirements, provincial authorities or their utilities are using RPS to source renewable generation resources and, in some cases, offer PPAs through competitive bidding processes. The competitive bidding process seeks to ensure that the RPS are achieved at the lowest possible cost and with the highest probability of project completion. By simplifying the negotiation and financing processes and decreasing the transactional costs for obtaining a long-term PPA, these mechanisms can contribute to meeting renewable energy generation goals. Several provinces have set a specific target percentage of electricity to be generated from renewable sources, including British Columbia (93% of total electricity from clean or renewable resources), Ontario (increase hydro energy capacity to 9,300 MW and to develop 10,700 MW of wind, solar and bioenergy installed capacity by 2021) and Quebec (develop 4,000 MW of wind energy capacity by 2015 whereby 3,262 MW have actually been developed with another 700 MW due to become active in the next two years and an additional 100 MW of wind energy for every 1,000 MW of additional hydroelectric power). Canada enjoys a unique abundance of hydrological resources. With an estimated installed hydroelectric capacity of more than 75,000 MW, it is the third largest hydroelectric energy producer in the world. Furthermore, according to the Canadian Hydropower Association, the country has an undeveloped, technically feasible potential estimated at 163,000 MW. Despite the competition for appropriate sites and the challenges associated with power transmission over great distances, the low operational costs and long project lives of these facilities suggest that hydroelectric power generation will remain a major affordable supply source for many years. Transmission corridors in Canada have traditionally run directly from major generation facilities to major demand centres, meaning that strategic investments in new transmission corridors will play an important role in the development of hydroelectric projects and other isolated renewable energy generation projects. Over the last few years, according to the National Energy Board, wind power has become commercially viable and emerged as the fastest growing segment of the renewable power industry in Canada. The Canadian Wind Energy Association ranks Canada as the seventh largest producer of wind energy in the world, with an installed wind power capacity of more than 11,205 MW, and sixth in the world for the amount of capacity added in 2015, with 1,506 MW of new wind energy commissioned in line with its objective to commission 1,500 MW of new wind energy annually over the next few years. Several reasons explain the robustness of the wind energy industry, including the improving cost-competitiveness of wind energy due to economies of scale and technological improvements, provincial RPS, relatively short construction time lines, favourable wind resources, including strong winds across a wide range of rural areas and vast shorelines, and provincial renewable energy RFPs. The usual challenges of resource availability and transmission exist in Canada and, in some areas, access to transmission lines with available capacity is an economic or regulatory consideration. Innergex Renewable Energy Inc Financial Review - 12

14 MANAGEMENT'S DISCUSSION AND ANALYSIS A solar energy industry has emerged in Canada in recent years, particularly in Ontario. During a conference sponsored by the Canadian Solar Industries Association held in May 2015, the Minister of Energy of Ontario stated that Ontario has 1550 MW of solar power installed in the province with another 825 MW contracted and under development. While more expensive than conventional and other renewable sources of energy, production costs for solar energy continue to decline due to technological improvements and economies of scale. The Ontario government has announced its intention to support its solar energy industry and is currently undertaking a 140 MW procurement of solar energy and is expected to procure another 150 MW in late SELECTED ANNUAL INFORMATION PRODUCTION Year ended December Power generated (MWh) 2,987,637 2,962,450 2,381,820 LTA (MWh) 3,054,642 2,964,070 2,502,562 Power generated as percentage of LTA 98% 100% 95% STATEMENT OF EARNINGS Revenues 246, , ,259 Adjusted EBITDA 183, , ,916 Adjusted EBITDA Margin 74.4% 74.3% 75.1% Net (loss) earnings (48,383) (84,378) 45,431 Net (loss) earnings attributable to owners of the parent (30,301) (54,853) 48,170 ($ per common share - basic) (0.37) (0.63) 0.43 ($ per common share - diluted) (0.37) (0.63) 0.43 Weighted average number of common shares (in 000s) 102,304 98,341 94,694 STATEMENT OF FINANCIAL POSITION Total assets 3,128,303 2,716,015 2,377,074 Current liabilities 185, , ,051 Long-term debt 2,160,438 1,610,800 1,313,718 Other long-term liabilities 217, , ,539 Liability portion of convertible debentures 93,430 80,018 79,831 Total non-current liabilities 2,471,576 1,951,755 1,605,088 Non-controlling interests 21,907 47,411 81,429 Equity attributable to owners 449, , ,506 DIVIDENDS Dividend declared per Class A Preferred Share Dividend declared per Class C Preferred Share Dividend declared per common share PAYOUT RATIO Dividends declared on common shares 63,646 59,549 54,967 Free Cash Flow 2 74,386 67,744 58,982 Payout Ratio 2 86% 88% 93% 1. The regular annual dividend is $1.4375; the initial dividend in 2013 was higher to reflect dividends accrued since the closing date of the Series C Preferred Shares offering of December 11, For more information on the calculation and explanation of the Corporation's Free Cash Flow and Payout Ratio, please refer to the "Free Cash Flow and Payout Ratio" section. Innergex Renewable Energy Inc Financial Review - 13

15 MANAGEMENT'S DISCUSSION AND ANALYSIS Comparison between 2015, 2014 and 2013 For the year ended December 31, 2015, the increases in power generated, revenues and Adjusted EBITDA are attributable mainly to the full-year contribution of the SM-1 hydroelectric facility acquired in June 2014, the addition of the Tretheway Creek hydroelectric facility commissioned at the end of 2015 and above-average wind regimes. The $48.4 million net loss for the year ended December 31, 2015, compared with a $84.4 million net loss for the same period last year, is attributable mainly to the recognition of an impairment expense of $51.7 million ($nil in 2014) by the Corporation in relation to some of its Prospective Projects and the smaller negative impact of derivative financial instruments, namely a $119.6 million realized loss on derivative financial instruments partly offset by a $81.4 million unrealized gain on derivative financial instruments, compared with a $121.7 million unrealized loss and an $8.4 million realized loss on derivative financial instruments in The increase in total assets is due mainly to investments by the Corporation in ongoing construction costs of the Corporation's Boulder Creek and Upper Lillooet River, the Big Silver Creek and the Mesgi'g Ugju's'n Development Projects and the Tretheway Creek project commissioned in October The increase in long-term debt is again attributable mainly to the addition of Development Projects-level debts partly offset by a reduction in the revolving credit term facility. The increase in the liability portion of convertible debentures in 2015 is due to the fact that the Corporation issued $100.0 million of new convertible debentures bearing interest at 4.25% while it redeemed or converted the outstanding principal amount of $80.5 million of the convertible debentures bearing interest at 5.75%. The decrease in equity attributable to owners and non-controlling interests is due mainly to the recognition of a net loss and the declaration of dividends on preferred and common shares in 2015, which was partially offset by the issuance of new common shares upon conversion, at the holders' request, of convertible debentures bearing interest at 5.75%. The increase in Free Cash Flow, which is attributable mainly to an increase in Adjusted EBITDA, more than offset the increase in dividends resulting from the greater number of shares outstanding, yielding a lower Payout Ratio of 86%. For the year ended December 31, 2014, the increases in power generated, revenues and Adjusted EBITDA are attributable mainly to the full-year contribution of the Magpie hydroelectric facility acquired in July 2013, the addition of the Kwoiek Creek and Northwest Stave River hydroelectric facilities commissioned at the end of 2013 and the addition of the SM-1 hydroelectric facility acquired in June The change from net earnings of $45.4 million to a net loss of $84.4 million is due mainly to a $121.7 million unrealized net loss on derivative financial instruments compared with an unrealized net gain of $45.2 million in 2013, which resulted from an increase in benchmark interest rates during the year. The increase in long-term debt is attributable mainly to drawings under the revolving term credit facility to fund construction costs of the Corporation's five Development Projects and to the addition of the SM-1 and Tretheway Creek project-level debts. The decrease in equity attributable to owners and non-controlling interests is due mainly to the recognition of a net loss and the declaration of dividends on preferred and common shares in The increase in Free Cash Flow, which is attributable mainly to an increase in Adjusted EBITDA, more than offset the increase in dividends resulting from the greater number of shares outstanding, yielding a lower Payout Ratio of 88%. Innergex Renewable Energy Inc Financial Review - 14

16 MANAGEMENT'S DISCUSSION AND ANALYSIS Impact on net (loss) earnings of the realized loss, the unrealized net (gain) loss on derivative financial Year ended December 31 instruments and the impairment of project development costs Net (loss) earnings (48,383) (84,378) 45,431 Add (Subtract): Unrealized net (gain) loss on derivative financial instruments (81,368) 121,685 (45,249) Realized loss on derivative financial instruments 119,557 8,366 3,259 Impairment of project development costs 51,719 (Recovery of) income tax expense related to above items (22,837) (32,096) 11,127 Share of unrealized net loss (gain) on derivative financial instruments of joint ventures, net of related income tax 1,043 2,804 (1,951) 19,731 16,381 12,617 Excluding the unrealized net gain or loss on derivative financial instruments, the realized loss on derivative financial instruments, the impairment of project development costs and the related income taxes, the net earnings for the year ended December 31, 2015 would have been $19.7 million, compared with net earnings of $16.4 million and of $12.6 million in 2014 and 2013 respectively. COMMISSIONING ACTIVITIES The Corporation reviewed the total project costs anticipated to achieve the completion of the Tretheway Creek project. Savings of $8 million has been realized over the previously estimated total project costs. Ownership % Gross installed capacity (MW) Gross estimated LTA 1 (GWh) PPA term (years) Total project costs Estimated 1 ($M) As at Dec. 31 ($M) Expected year-one Revenues 1 ($M) Adjusted EBITDA 1 ($M) HYDRO (British Columbia) Tretheway Creek This information is intended to inform readers of the projects' potential impact on the Corporation's results. Actual results may vary. Tretheway Creek The construction of this hydroelectric facility began in October Construction and commissioning activities were completed ahead of time. The costs of the Tretheway Creek project are reviewed downward by an amount of $8.0 million and are currently estimated at $103.5 million (compared with $111.5 million in 2014). The estimate of the total project costs was revised mainly to take into consideration a reduction in the unused contingencies on the construction costs. The facility began commercial operations with an effective commissioning date of October 27, Tretheway Creek s average annual production is estimated to reach 81,000 MWh, enough to power more than 7,300 BC households. In its first full year of operation, it is expected to generate revenues and Adjusted EBITDA of approximately $8.7 million and $7.2 million respectively (compared with $9.0 million and $7.5 million in 2014). The $0.3 million reduction in these estimates compared with prior guidance reflects a lower inflation rate in adjusting the expected selling price for electricity. All of the electricity the facility produces is covered by a 40-year fixed-price power purchase agreement with BC Hydro, which was obtained under that province s 2008 Clean Power Call Request for Proposals and which provides for an annual adjustment to the selling price based on a portion of the Consumer Price Index. Innergex Renewable Energy Inc Financial Review - 15

17 MANAGEMENT'S DISCUSSION AND ANALYSIS DEVELOPMENTS IN 2015 Closing of the Project Financing for the Boulder Creek and Upper Lillooet River Projects On March 17, 2015, the Corporation announced the closing of a $491.6 million non-recourse construction and term project financing for the Boulder Creek and Upper Lillooet River run-of-river hydroelectric projects located in British Columbia. The loan comprises three facilities or tranches: A $191.6 million construction loan carrying a fixed interest rate of 4.22%; following the start of the facilities commercial operation, it will convert into a 25-year term loan and the principal will be amortized over a 20-year period starting in the sixth year; A $250 million construction loan carrying a fixed interest rate of 4.46%; following the start of the facilities commercial operation, it will convert into a 40-year term loan and the principal will begin to be amortized upon maturity of the 25- year term loan; A $50 million construction loan carrying a fixed interest rate of 4.46%; following the start of the facilities commercial operation, it will convert into a 40-year term loan and its principal will be reimbursed at maturity. The financing was arranged by The Manufacturers Life Insurance Company as agent and lead lender with the Caisse de Dépôt et placement du Québec and The Canada Life Assurance Company as lenders. Concurrent with the closing of the financing, the Corporation settled the bond forward contracts used to hedge the interest rate prior to the closing of the financing in order to protect the expected returns on the projects, giving rise to a $68.0 million realized loss on derivative financial instruments. This is equivalent to a fixed interest rate of approximately 5.66% on the loans and is well within the parameters of the economic model for this project. Please refer to the "Financial Position" section for more information. Renewal of Normal Course Issuer Bid On March 19, 2015, the Corporation announced it was renewing its normal course issuer bid ("NCIB"), which enables it to purchase for cancellation up to 1 million (or approximately 1.0%) of its issued and outstanding common shares between March 24, 2015, and March 23, Saik'uz First Nation ( Saik uz ) and the Corporation sign a partnership to develop a wind energy project in British Columbia On April 17, 2015, Saik uz and the Corporation announced the signing of an agreement to jointly develop a prospective wind energy project at Nulki Hills near Vanderhoof, British Columbia. The Corporation and Saik uz have agreed on the commercial terms for a partnership to develop the proposed Nulki Hills prospective wind project, representing up to 210 MW of clean renewable power. Closing of the Project Financing for the Big Silver Creek Project On June 22, 2015, the Corporation announced the closing of a $197.2 million non-recourse construction and term project financing for the Big Silver Creek run-of-river hydroelectric project located in British Columbia. The loan comprises three facilities or tranches: A $51.0 million construction loan carrying a fixed interest rate of 4.56%; following the start of the facility's commercial operation, it will convert into a 25-year term loan and the principal will be amortized over a 18-year period starting in the seventh year; A $128.3 million construction loan carrying a fixed interest rate of 4.76%; following the start of the facility's commercial operation, it will convert into a 40-year term loan and the principal will begin to be amortized upon maturity of the 25- year term loan; A $17.9 million construction loan carrying a fixed interest rate of 4.76%; following the start of the facility's commercial operation, it will convert into a 40-year term loan and its principal will be reimbursed at maturity. The financing was arranged by The Manufacturers Life Insurance Company as agent and lead lender with the Caisse de Dépôt et placement du Québec as lender. Innergex Renewable Energy Inc Financial Review - 16

18 MANAGEMENT'S DISCUSSION AND ANALYSIS Concurrent with the closing of the financing, the Corporation settled the bond forward contracts used to hedge the interest rate prior to the closing of the financing in order to protect the expected returns on the projects, giving rise to a $24.7 million realized loss on derivative financial instruments. This is equivalent to a fixed interest rate of approximately 5.75% on the loans and is well within the parameters of the economic model for this project. Please refer to the "Financial Position" section for more information. Revolving Term Credit Facility Decreased as Planned On June 30, 2015, the Corporation's revolving term credit facility went from $475 million back to $425 million as per the terms of the amending agreement executed on November 6, 2014, to temporarily increase the facility in order to provide greater financing flexibility until such time as the Corporation closed the project-level financings that remained to be put in place. Issuance of $100.0 million of convertible debentures bearing interest at 4.25% and redemption or conversion of $79.6 million of convertible debentures bearing interest at 5.75% On July 20, 2015, the Corporation entered into a bought deal agreement for the issuance of $100.0 million in convertible unsecured subordinated debentures bearing interest at a rate of 4.25% and issued a notice of redemption to the holders of its outstanding convertible unsecured subordinated debentures bearing interest at rate of 5.75% and maturing on April 30, The $100.0 million offering of convertible debentures bearing interest at 4.25% was completed on August 10, The debentures are convertible at the holder s option into Innergex common shares at a conversion price of $15.00 per share, representing a conversion rate of common shares per $1,000 principal amount of debentures. They will mature on August 31, 2020, and will not be redeemable before August 31, 2018, except in certain limited circumstances. The debentures are traded on the Toronto Stock Exchange under the symbol "INE.DB.A". The net proceeds of the offering were used to reduce drawings under the revolving term credit facility; the funds available under this facility were used to redeem the debentures described below and can be drawn, when required, to fund future acquisitions, development projects and general corporate purposes. The redemption or conversion of the outstanding principal amount of $79.6 million of the convertible debentures bearing interest at 5.75% was completed on August 20, Of that principal amount, $38.0 million was converted at the holders request into 3,566,851 Innergex common shares at a conversion price of $10.65 per share. The remaining $41.6 million was redeemed at a price of $1,000 per debenture, plus accrued and unpaid interest up to August 19, 2015, inclusively and was financed with drawings under the Corporation s revolving term credit facility. Amendment of the Normal Course Issuer Bid and implementation of an automatic purchase plan Effective September 4, 2015, the Corporation's normal course issuer bid was amended in order to increase the maximum number of shares that may be repurchased and to implement an automatic purchase plan. The bid commenced on March 24, 2015 and will terminate on March 23, The maximum number of common shares that the Corporation may purchase for cancellation has increased from 1,000,000, or approximately 1%, to 2,000,000, or approximately 2%, of its issued and outstanding common shares. No other terms of the bid were amended. In addition, the Corporation has entered into an automatic purchase plan agreement with a designated broker to allow for purchases of its common shares during times when it would ordinarily not be permitted to do so due to self-imposed blackout periods or regulatory restrictions. As at December 31, 2015, the Corporation had purchased for cancellation 1,190,173 common shares at an average price of $ Closing of the Project Financing for the Mesgi'g Ugju's'n Project On September 28, 2015, the Corporation and its partner announced the closing of a $311.7 million non-recourse construction and term project financing for the Mesgi'g Ugju's'n wind project located in Quebec. The financing comprises three facilities or tranches: Innergex Renewable Energy Inc Financial Review - 17

19 MANAGEMENT'S DISCUSSION AND ANALYSIS A $49.2 million floating-rate construction loan carrying a swap-fixed interest rate of 2.41%; following the start of the wind farm s commercial operation, it will be repaid with the proceeds of the scheduled reimbursement by Hydro- Québec for the Mesgi g Ugju s n electrical substation; A $103.0 million floating-rate construction loan carrying a swap-fixed interest rate of 3.54%; following the start of the wind farm s commercial operation, it will convert into a 9.5-year term loan and the principal will be amortized over the term of the loan; A $159.5 million construction loan carrying a fixed interest rate of 4.28%; following the start of the wind farm s commercial operation, it will convert into a 19.5-year term loan and the principal will begin to be amortized upon maturity of the 9.5-year term loan. The financing was arranged and underwritten by National Bank Financial Markets, as co-lead arranger and sole book runner, and SunLife Assurance Company of Canada, as co-lead arranger. Concurrent with the closing of the financing, the Corporation settled the bond forward contracts used to hedge the interest rate prior to the closing of the financing in order to protect the expected returns on the projects, giving rise to a $27.0 million realized loss on derivative financial instruments. This is equivalent to a fixed interest rate of approximately 4.97% on the loans and is well within the parameters of the economic model for this project. Please refer to the "Financial Position" section for more information. Signing of a Memorandum of Understanding with the Federal Electricity Commission of Mexico On October 13, 2015, the Corporation signed a memorandum of understanding with the Comisión Federal de Electricidad ( CFE ) to jointly study a number of renewable energy project opportunities in Mexico with the aim of jointly developing selected projects. The main purpose of this agreement is to coordinate efforts and develop activities that will allow the Corporation and CFE to define their joint participation in the development of prospective renewable energy projects, in particular small hydroelectric plants of less than 200 MW. Potential Acquisition of the Walden Hydroelectric Project On December 15, 2015, the Corporation and the Cayoose Creek Band announced the signature of an agreement for the joint acquisition of the Walden North Hydroelectric project near Lillooet, British Columbia. The Corporation and Cayoose Creek Development Corp., the economic arm of Cayoose Creek Band, have formed a limited partnership to jointly acquire the assets of the Walden project from FortisBC for $9.2 million. The closing of the acquisition is subject to customary conditions, and set to be completed in the first quarter of The Walden North Hydroelectric project is a 16 MW facility located on private land in Cayoosh Creek near Lillooet, British Columbia. Innergex Renewable Energy Inc Financial Review - 18

20 MANAGEMENT'S DISCUSSION AND ANALYSIS DEVELOPMENT PROJECTS The Corporation reviewed the total project costs anticipated to achieve the completion of the Development Projects. Savings of $28.0 million is expected over the previously estimated total project costs. PROJECTS UNDER CONSTRUCTION Ownership % Gross installed capacity (MW) Expected COD 1 Gross estimated LTA 2, 3 (GWh) PPA term (years) Total project costs Estimated 2 ($M) As at Dec. 31 ($M) Expected year-one Revenues 2 ($M) Adjusted EBITDA 2 ($M) HYDRO (British Columbia) Upper Lillooet River Boulder Creek Big Silver Creek WIND (Quebec) Mesgi'g Ugju's'n Commercial operation date. 2. This information is intended to inform readers of the projects' potential impact on the Corporation's results. Actual results may vary. These estimates are up-to-date as at the date of the MD&A. 3. Upon commissioning, LTA figures may be updated to reflect design optimization or constraints or selection of different turbines. Please refer to the Forward-Looking Information section for more information. 4. Corresponding to 100% of this facility. 5. The COD should be achieved in the first quarter of 2017 for the Upper Lillooet hydroelectric project and in the second quarter of 2017 for the Boulder Creek hydroelectric project. Commercial operation is delayed due to the forest fire that forced the interruption of construction activities. BC Hydro accepted that the fire constitutes a Force Majeure event and consequently confirmed that the COD could be delayed up to 98 Force Majeure days. If financial consequences nonetheless result from the forest fire, the Upper Lillooet River and Boulder Creek projects expect to be indemnified for such delays by virtue of their insurance coverage. Upper Lillooet River and Boulder Creek (the "Upper Lillooet Hydro Project" or "ULHP") The construction of the Upper Lillooet River and Boulder Creek hydroelectric facilities began in October On March 17, 2015, the Corporation announced the closing of a $491.6 million non-recourse construction and term project financing for both these projects. Construction activities have resumed after being halted for two months due to a forest fire that swept through the area on July 4. Damage to the project site from the fire was very limited and all structures and equipment remained intact, except for a portion of the transmission line between the two powerhouses. As at the date of this MD&A, the installation of the joint transmission line, the powerhouses, the intakes and the tunnels are well under way. Both generators for the Boulder facility were delivered in mid-december and stored in the powerhouse. The Corporation and its contractors are working throughout the winter, focusing mainly on the tunnels to make up for some of the time lost to the forest fire. On December 23, BC Hydro notified the ULHP that it accepted a claim for Force Majeure for the forest fire and confirmed that the commissioning date could be extended by 98 Force Majeure days. The insurance claims process is ongoing and will take time to complete. In any case, the Corporation expects to be indemnified and to suffer no significant adverse financial consequences from the forest fire. The costs of the Upper Lillooet and Boulder Creek hydroelectric facilities were revised upward by $17.0 million ($12.1 million for the Upper Lillooet project and $4.9 million for the Boulder Creek project). The total project costs for the Upper Lillooet facility are currently estimated at $327.1 million (compared with $315.0 million in 2014) while they are reassessed at $124.1 million (at $119.2 million in 2014) for the Boulder Creek facility. The estimates of the total project costs have been revised to take into account incremental costs associated with the geological conditions in the tunnels and additional interest expenses from the higher amount of project financing. Big Silver Creek Construction of this hydroelectric facility began in June On June 22, 2015, the Corporation announced the closing of a $197.2 million non-recourse construction and term project financing for this project. As at the date of this MD&A, the civil works for the intake, tunnel, penstock, powerhouse and tailrace have been completed. The majority of the turbines and generators have been delivered to site and their installation is under way. Transmission line construction continued for both the terrestrial line and the submarine cables. Procurement and delivery of the electrical equipment were under way. Innergex Renewable Energy Inc Financial Review - 19

21 MANAGEMENT'S DISCUSSION AND ANALYSIS The costs of the Big Silver Creek project were revised downward by $10.0 million and are currently estimated at $206.0 million (compared with $216.0 million in 2014). The estimates of the total project costs have been revised, mainly to take into account a reduction in the unused contingencies for the construction costs. Commercial operation is expected to begin in the third quarter of Mesgi'g Ugju's'n Construction of this wind farm began in May On September 28, 2015, the Corporation and its partner announced the closing of $311.7 million non-recourse construction and term project financing for this project. As at the date of this MD&A, the access roads and wind turbines generator ("WTG") areas have been completed. All the WTG foundations have been completed but one, which will be backfilled in early spring The electrical works will not be completed during the winter but will resume in 2016, along with other activities. As planned, the other construction activities have been halted for the winter period and will also resume in the spring of The cost of the Mesgi'g Ugju's'n wind project is currently estimated at $305.0 million (compared with $340.0 million in 2014). The $35.0 million reduction in the Corporation's estimated project costs reflects the lower cost of project financing and associated financial costs relative to the initial forecasts and the use of larger turbines, which incidentally reduces the number of turbines, equipment costs and civil engineering construction associated costs. The end of construction and the commissioning of the Mesgi g Ugju s n wind farm is expected for the end of PROSPECTIVE PROJECTS With a combined potential net installed capacity of 3,280 MW (gross 3,530 MW), all the Prospective Projects are in the preliminary development stage. Some Prospective Projects are targeted toward specific future requests for proposals, such as the current request for proposals for new wind and solar energy in Ontario. Other Prospective Projects will be available for future requests for proposals yet to be announced or are targeted toward negotiated power purchase agreements with public utilities or other creditworthy counterparties. There is no certainty that any Prospective Project will be realized. OPERATING RESULTS Production of electricity for the year was 98% of the long-term average ("LTA") production due mainly to belowaverage water flows in all markets but above-average results for the wind and solar regimes. Production increased 1%, revenues increased 2% and Adjusted EBITDA increased 2% in The increase in production and revenues is attributable mainly to the full-year contribution of the SM-1 hydroelectric facility acquired in June 2014 and the contribution of the wind sector partly offset by lower production in British Columbia. The Corporation's operating results for the year ended December 31, 2015, are compared with the operating results for the same periods in Electricity Production When evaluating its operating results, a key performance indicator for the Corporation is to compare actual electricity generation with a long-term average for each hydroelectric facility, wind farm and solar farm. These long-term averages are determined to allow long-term forecasting of the expected power generation for each of the Corporation's facilities. Innergex Renewable Energy Inc Financial Review - 20

22 MANAGEMENT'S DISCUSSION AND ANALYSIS Year ended December 31 Production (MWh) LTA (MWh) Production Average as a % of price Production LTA ($/MWh) 2 (MWh) 1 LTA (MWh) Production as a % of LTA Average price ($/MWh) 2 HYDRO Quebec 696, ,930 99% , ,205 99% Ontario 70,683 74,544 95% ,333 74, % British Columbia 1,428,953 1,518,712 94% ,509,737 1,513, % United States 42,675 46,800 91% ,083 46,800 96% Subtotal 2,238,376 2,339,986 96% ,245,224 2,249, % WIND Quebec 709, , % , , % SOLAR Ontario 39,549 38, % ,119 38, % Total 2,987,637 3,054,642 98% ,962,450 2,964, % The Umbata Falls hydroelectric facility and the Viger-Denonville wind farm are treated as joint ventures and accounted for using the equity method; their revenues are not included in the Corporation's consolidated revenues and, for the sake of consistency, their electricity production figures have been excluded from the production table. For more information on the Corporation's joint ventures, please refer to the "Investments in Joint Ventures" section. 2. Including all payment adjustments related to the month, day and hour of delivery, to environmental attributes and to the ecoenergy Initiative, as applicable. During the year ended December 31, 2015, the Corporation's facilities produced 2,988 GWh of electricity or 98% of the LTA of 3,055 GWh. Overall, the hydroelectric facilities produced 96% of their LTA, due mainly to below-average water flows in all markets. Overall, the wind farms produced 105% of their LTA, due mainly to above-average wind regimes. The Stardale solar farm produced 104% of its LTA, due mainly to above-average solar regimes. For more information on operating segment results, please refer to the "Segment Information" section. The production increase of 1% compared with the same period last year is attributable to the full-year contribution of the SM-1 hydroelectric facility acquired in June 2014 and the better performance of the wind farms, partially offset by below-average water flows in Ontario, British Columbia and the United-States. The overall performance of the Corporation's facilities for the year ended December 31, 2015, demonstrates the benefits of geographic diversification and the complementarity of hydroelectric, wind and solar power generation. Additional Information Power Purchase Agreements The 34 Operating Facilities sell the generated power under long-term PPAs to rated public utilities or other creditworthy counterparties. For Operating Facilities in Quebec, Ontario and British Columbia, PPAs include a base price and, in some cases, a price adjustment depending on the month, day and hour of delivery, except for the Miller Creek hydroelectric facility, for which the price is based on a formula using the Platts Mid-C pricing indices (this facility accounted for 2% of revenues in 2015). For the Horseshoe Bend hydroelectric facility located in Idaho, USA, 85% of the price is fixed and 15% is adjusted annually as determined by the Idaho Public Utility Commission. Portneuf In addition to revenue from the power generated at the three Portneuf facilities, the Corporation receives cash payments from Hydro-Québec to compensate for the partial diversion of the water flow that would have otherwise been available to the Corporation's plants. These payments are based on long-term average annual water flows over 20 years. Although these facilities are exempt from annual hydrological variations under the virtual energy provisions included in the long-term PPAs with Hydro-Québec, they must remain in operation in order to receive financial compensation. As such, the payments are contingent on turbine availability and maximum production with the water resources made available by Hydro-Québec. Innergex Renewable Energy Inc Financial Review - 21

23 MANAGEMENT'S DISCUSSION AND ANALYSIS Inflation Protection Most of the Corporation's PPAs for Operating Facilities include a clause that adjusts for the effects of inflation: all PPAs for Quebec hydroelectric facilities except Magpie and the second PPA (22 MW) for SM-1 provide for an annual CPI-based power rate increase of between 3% and 6%; the PPA for the Magpie hydroelectric facility provides for an annual power rate increase of 1%; the second PPA (22 MW) for the SM-1 hydroelectric facility provides for an annual power rate increase of 2%; the PPAs for the Glen Miller and Umbata Falls hydroelectric facilities provide for an annual power rate adjustment based on 15% of the CPI; all PPAs for British Columbia hydroelectric facilities except Kwoiek Creek, Brown Lake and Miller Creek provide for an annual power rate adjustment based on 50% of the CPI; for the six facilities owned by Harrison Hydro Limited Partnership, this inflation protection is partly offset by the inflation component of the real-return bonds; the PPA for the Kwoiek Creek hydroelectric facility in British Columbia provides for an annual power rate adjustment based on 30% of the CPI; the PPA for the Brown Lake hydroelectric facility in British Columbia provides for an annual power rate increase of 3%; all PPAs for Quebec wind farms provide for an annual power rate adjustment based on approximately 20% of the CPI. Power Purchase Agreements Up for Renewal The PPA for the 8.0 MW St-Paulin hydroelectric facility reached the end of its initial 20-year term in November The Corporation had sent Hydro-Québec a notice of automatic renewal of the PPA for an additional 20-year term. Following initial discussions, the Corporation and Hydro-Québec could not reach agreement on the renewal terms and conditions and the Corporation subsequently filed a notice of arbitration. The Corporation has agreed with Hydro-Québec to suspend its arbitration proceeding until a decision is made in another arbitration proceeding already under way between Hydro-Québec and other independent power producers. In the meantime, Hydro-Québec has agreed to maintain the terms and conditions of the St- Paulin PPA until 30 days following the decision in this other arbitration proceeding. The PPA for the 5.5 MW Windsor hydroelectric facility reached the end of its initial 20-year term in January 2016 and the Corporation sent Hydro-Québec a notice of automatic renewal of the PPA for an additional 20-year term. Financial Results Year ended December Revenues 246, % 241, % Operating expenses 40, % 41, % General and administrative expenses 14, % 15, % Prospective project expenses 8, % 5, % Adjusted EBITDA 183, % 179, % Finance costs 83,130 86,537 Other net expenses 116,764 7,797 Depreciation and amortization 75,478 74,092 Impairment of project development costs 51,719 Share of (earnings) loss of joint ventures (note 1) (1,562) 701 Unrealized net (gain) loss on derivative financial instruments (81,368) 121,685 Recovery of income tax expense (12,040) (26,872) Net loss (48,383) (84,378) Net loss attributable to: Owners of the parent (30,301) (54,853) Non-controlling interests (18,082) (29,525) (48,383) (84,378) Basic net loss per share ($) (0.37) (0.63) 1. The Umbata Falls hydroelectric facility and Viger Denonville wind farm are treated as joint ventures and the Corporation's interests in these facilities are required to be accounted for using the equity method. For more information on the Corporation's joint ventures, please refer to the "Investments in Joint Ventures" section. Innergex Renewable Energy Inc Financial Review - 22

24 MANAGEMENT'S DISCUSSION AND ANALYSIS Revenues For the year ended December 31, 2015, the Corporation recorded revenues of $246.9 million, compared with $241.8 million in This 2% increase is attributable mainly to the full-year contribution of the SM-1 hydroelectric facility acquired in June 2014 and the higher wind regimes in Quebec, partially offset by lower water flows in British Columbia. Expenses Operating expenses consist primarily of the operators' salaries, insurance premiums, expenditures related to operation and maintenance, property taxes and royalties. For the year ended December 31, 2015, the Corporation recorded operating expenses of $40.9 million ($41.5 million in 2014). This 1% decrease is due mainly to variable costs associated with the lower production in British Columbia, reduced operating expenses in the United States and resources being devoted to prospective projects partly offset by the full-year operation of the SM-1 hydroelectric facility. General and administrative expenses consist primarily of salaries, professional fees and office expenses. For the year ended December 31, 2015, general and administrative expenses totalled $14.2 million ($15.1 million in 2014). This 6% decrease stems mainly from resources being devoted to prospective project expenses following the Corporation's strategy to develop international markets. Prospective project expenses include the costs incurred for the development of Prospective Projects. They result from the number of Prospective Projects that the Corporation has chosen to advance and the resources required to do so. For the year ended December 31, 2015, prospective project expenses totalled $8.0 million ($5.7 million in 2014). This 41% increase is related mainly to the advancement of a number of prospective projects, to pursuing opportunities in new international markets and to the current request for proposals in Ontario. Adjusted EBITDA When evaluating its financial results, a key performance indicator for the Corporation is to measure Adjusted EBITDA, which is defined as revenues less operating expenses, general and administrative expenses and prospective project expenses. For the year ended December 31, 2015, the Corporation recorded Adjusted EBITDA of $183.7 million, compared with $179.6 million for the same period last year. This 2% increase is due mainly to the increase in production and revenues explained above. As a result, the Adjusted EBITDA Margin rose from 74.3% to 74.4%. Finance Costs Finance costs include interest on long-term debt and convertible debentures, inflation compensation interest, amortization of financing fees, accretion of long-term debt and convertible debentures, accretion expenses on other liabilities, and other finance costs. For the year ended December 31, 2015, finance costs totalled $83.1 million ($86.5 million in 2014). The decrease for the year is due mainly to the much lower inflation compensation interest on the real-return bonds ($2.9 million compared with $6.7 million in 2014), which more than offset the increase in interest expenses resulting from higher levels of debt.the decrease is partially offset by the full-year contribution of the SM-1 hydroelectric facility. As at December 31, 2015, 99% of the Corporation's outstanding debt, including convertible debentures, was fixed or hedged against interest rate movements (91% as at December 31, 2014). The effective all-in interest rate on the Corporation's debt and convertible debentures was 5.12% as at December 31, 2015 (5.25% as at December 31, 2014). The decrease stems mainly from the full-year contribution of the SM-1 project debt, which bears a fixed interest rate of 3.30% following its adjustment to fair market value upon consolidation, the addition of the Tretheway Creek project debt, which bears a fixed interest rate of 4.99%, the addition of the Boulder Creek and Upper Lillooet River project debts, which bear a weighted average fixed interest rate of 4.36%, the addition of the Big Silver Creek project debt, which bears a weighted average fixed interest rate of 4.71% and the addition of the Mesgi'g Ugju's'n project financing, which actually bears a fixed interest rate of 4.28%, partly offset by the full-year contribution of the debenture on the SM-1 facility, which bears a fixed interest rate of 8.00%. Innergex Renewable Energy Inc Financial Review - 23

25 MANAGEMENT'S DISCUSSION AND ANALYSIS Other Net Expenses Other net expenses include transaction costs, realized losses on derivative financial instruments, realized gain on contingent considerations, realized losses on foreign exchange, loan impairment and other net revenues. For the year ended December 31, 2015, the Corporation recorded other net expenses of $116.8 million ($7.8 million in 2014). The change for the year stems mainly from the $119.6 million realized loss on derivative financial instruments resulting from the settlement of the Boulder Creek, Upper Lillooet River, Big Silver Creek and Mesgi'g Ugju's'n bond forward contracts upon closing of the projects' financing. This change was partly offset by the recognition of a $3.4 million realized gain on contingent considerations in relation to amounts payable on the future development of the prospective projects in British Columbia acquired from Cloudworks Energy Inc. in 2011, which prospective projects were impaired as at December 31, Depreciation and Amortization For the year ended December 31, 2015, depreciation and amortization expenses totalled $75.5 million ($74.1 million in 2014). This increase is attributable mainly to the full-year contribution of the SM-1 hydroelectric facility acquired in June 2014 and the full-year amortization of an extended two-year warranty contracted for Phase II of the Gros-Morne wind farm. Impairment of project development costs For the years ended December 31, 2015 and 2014, the Corporation conducted impairment tests on its project development costs. Based on the results of these tests, a $51.7 million impairment charge was required in 2015 for projects for which uncertainties exist regarding the timing and profitability of any development. The impairment resulted in a $13.6 million recovery of income taxes. For the year ended December 31, 2014, no impairment charge was required. In 2011, full ownership of hydroelectric projects in British Columbia in various stages of development (with a potential aggregate installed capacity of over 800 MW) resulted from the acquisition of Cloudworks Energy Inc. Accordingly, an amount of $51.7 million for Prospective Projects was recorded following the acquisition. However, as at December 31, 2015, BC Hydro's Site C (a mega hydroelectric station that should provide around 1,100 MW of capacity and produce about 5,100 GWh of electricity a year) is moving forward. Construction of the project started in summer Furthermore, in September 2015, the BC Supreme Court dismissed a petition seeking an order quashing the Environmental Assessment Certificate issued by the Minister of the Environment and the Minister of Forests, Lands and Natural Resource Operations for the project. In November 2015, BC Hydro and the BC Government announced the awarding of a $1.5 billion construction contract for Site C. The odds of success on litigation led by First Nations and various environmental groups against Site C are fairly remote, as construction activities are in progress. BC Hydro publicly announced that based on their forecasts, it would likely be the early 2030s before the utility foresees the need for a significant block of new electricity from Independent Power Producers. Consequently, in the year ended on December 31, 2015, the Corporation recognized an impairment of $51.7 million ($nil in 2014), resulting in a recovery of income taxes of $13.6 million, related to its BC Prospective Projects, for which it retains ownership of the licenses that it might develop in the future. Simultaneously, the contingent considerations related to these Prospective Projects were reversed resulting in a realized gain of $3.4 million. Share of (earnings) loss of joint ventures For the year ended December 31, 2015, the Corporation recorded a share of earnings of joint ventures of $1.6 million ($0.7 million share of loss of Joint Ventures in 2014). Please refer to the "Investments in Joint Ventures" section for more information. Derivative Financial Instruments The Corporation uses derivative financial instruments to manage its exposure to the risk of rising interest rates on its existing and upcoming debt financing and its exposure to the risk of rising foreign currencies on its equipment purchases ( Derivatives ), thereby protecting the economic value of its projects. Innergex also has derivative financial instruments embedded in some of its PPAs (the minimum 3% inflation clause applied to the selling price). The Corporation does not own or issue financial instruments for speculative purposes. Since bond forwards are linked to long-term bonds and interest rate swaps are entered into for a term equal in length to the underlying debt amortization schedule, which can reach 30 years, a Derivative's fair market value can be very sensitive to quarter-to-quarter changes in long-term interest rates. Since October 2014, the Corporation has used hedge accounting for new Derivatives and, since April 1, 2015, it has decided to use hedge accounting for its existing Derivatives used to fix the interest rate on the project-level debts (with the exception of Umbata Falls) and on most of its revolving term credit facility in order to reduce the fluctuations in net earnings or losses resulting from unrealized gains or losses on these Derivatives during a given period. Under hedge accounting, most of the unrealized gains or losses on Derivatives that arise from a decrease or increase in the benchmark interest rate will be recorded in other comprehensive income, while only the portion of the unrealized gain or loss related to the "ineffectiveness" and the settlement of the Derivatives will be recorded in net earnings. Innergex Renewable Energy Inc Financial Review - 24

26 MANAGEMENT'S DISCUSSION AND ANALYSIS For the year ended December 31, 2015, the Corporation recognized an unrealized net gain on derivative financial instruments of $81.4 million, due mainly to the reversal of the unrealized loss accrued upon settlement of the bond forward contracts concurrently with the closing of the Boulder Creek and Upper Lillooet River project financing of $491.6 million in March, the Big Silver Creek project financing of $197.2 million in June and the Mesgi'g Ugju's'n project financing of $311.7 million in September. For the corresponding period last year, the Corporation recognized an unrealized net loss on derivative financial instruments of $121.7 million, due mainly to the decrease in benchmark interest rates since December 31, In March 2015, the Corporation announced the closing of a $491.6 million financing and concurrently settled the corresponding bond forward contracts for the Boulder Creek and Upper Lillooet River hydroelectric projects; in June 2015, it announced the closing of a $197.2 million financing and concurrently settled the corresponding bond forward contracts for the Big Silver Creek hydroelectric project; and in September 2015, it announced the closing of a $311.7 million financing and concurrently settled the corresponding bond forward contracts for the Mesgi'g Ugju's'n wind project. For the year ended December 31, 2015, these bond forward contract settlements resulted in a realized loss of $119.6 million (in 2014 a realized loss of $8.4 million following the closing of the Tretheway Creek project financing). As at December 31, 2015, the Corporation had no Derivatives to be settled upon the closing of a project financing since all financings were put in place in Income Tax Expense (Recovery) For the year ended December 31, 2015, the Corporation recorded a current income tax expense of $3.1 million ($3.0 million in 2014) and a deferred income tax recovery of $15.2 million ($29.9 million in 2014). The deferred income tax recovery is due in part to the recognition of an accounting loss before income taxes resulting from the $119.6 million realized loss resulting from the settlement of Derivatives and the recognition by the Corporation of an impairment of $51.7 million related to its British Columbia Prospective Projects, partly offset by the $81.4 million reversal of unrealized gain accrued upon settlement of Derivatives. The deferred tax recovery for the same period last year is due mainly to an unrealized net loss on Derivatives. Net Loss For the year ended December 31, 2015, the Corporation recorded a net loss of $48.4 million (basic and diluted net loss of $0.37 per share), compared with a net loss of $84.4 million (basic and diluted net loss of $0.63 per share) in This is attributable mainly to a $51.7 million impairment of project development costs and a smaller negative impact of Derivatives, namely a $119.6 million realized loss on derivative financial instruments partly offset by a $81.4 million unrealized gain on derivative financial instruments, compared with a $8.4 million realized loss and a $121.7 million unrealized loss on derivative financial instruments last year. Innergex Renewable Energy Inc Financial Review - 25

27 MANAGEMENT'S DISCUSSION AND ANALYSIS Main items explaining the change in a net loss for the year ended December 31, 2015, compared with the net loss for the corresponding period in 2014 Main items Positive impact Change Explanation Unrealized net (gain) loss on derivative financial instruments 203,053 Due mainly to the reversal of unrealized losses upon settlement of the Boulder Creek, Upper Lillooet River, Big Silver Creek and Mesgi'g Ugju's'n bond forward contracts, compared with an unrealized net loss on derivative financial instruments resulting from a decrease in benchmark interest rates for Revenues 5,035 Due mainly to the full-year contribution of the SM-1 hydroelectric facility acquired in June 2014 and the higher wind regimes in Quebec, partially offset by lower water flows in British Columbia. Main items Negative impact Change Explanation Other net expenses 108,967 Due mainly to a realized net loss on derivative financial instruments of $119.6 million resulting from the settlement of the Boulder Creek, Upper Lillooet River, Big Silver Creek and Mesgi'g Ugju's'n bond forwards upon closing of the project financings, compared with a realized loss of $8.4 million due to the settlement of the Tretheway bond forward in Impairment of project development costs 51,719 Due to an impairment following the low probability of being able to develop the British Columbia hydroelectric prospective projects acquired in Deferred recovery of income tax 14,724 Due mainly to a smaller recovery of income tax on a smaller accounting loss resulting from a realized net loss on derivative financial instruments and an impairment expense on prospective projects partly offset by an unrealized gain on derivative financial instruments, as mentioned above compared with a more significant unrealized loss on derivative financial instruments in Non-controlling Interests Non-controlling interests are related to the six hydroelectric facilities of the Harrison Hydro Limited Partnership, the Creek Power Inc. subsidiaries, the Kwoiek Creek Resources Limited Partnership, the Mesgi'g Ugju's'n (MU) Wind Farm, L.P., the Magpie Limited Partnership, the Innergex Sainte-Marguerite S.E.C. entity and their respective general partners. For the year ended December 31, 2015, the Corporation allocated a loss of $18.1 million to non-controlling interests (compared with a loss of $29.5 million in 2014). Please refer to the "Non-Wholly Owned Subsidiaries" section for more information. Number of Common Shares Outstanding Weighted average number of common shares outstanding (000s) Year ended December Weighted average number of common shares 102,304 98,341 Effect of dilutive elements on common shares Diluted weighted average number of common shares 102,587 98, Stock options for which the exercise price was above the average market price of common shares were excluded from the calculation of diluted weighted average number of shares outstanding. For the year ended December 31, 2015, 2,579,684 of the 3,425,684 stock options (1,830,684 of the 3,470,684 in 2014) were dilutive. During the year ended December 31, 2015, none of the 6,666,667 shares that can be issued on conversion of convertible debentures were dilutive (none of the 7,558,684 shares were dilutive in 2014). Innergex Renewable Energy Inc Financial Review - 26

28 MANAGEMENT'S DISCUSSION AND ANALYSIS The Corporation s Equity Securities As at February 24, 2016 December 31, 2015 December 31, 2014 Number of common shares 104,006, ,938, ,672,000 Number of 4.25% convertible debentures 100, ,000 Number of 5.75% convertible debentures 80,500 Number of Series A Preferred Shares 3,400,000 3,400,000 3,400,000 Number of Series C Preferred Shares 2,000,000 2,000,000 2,000,000 Number of stock options outstanding 3,425,684 3,425,684 3,470,684 As at the date of this MD&A, the increase in the number of common shares since December 31, 2015, is attributable to the issuance of shares under the Corporation's Dividend Reinvestment Plan ("DRIP"). The increase in the number of common shares since December 31, 2014, is attributable mainly to the conversion, at the holders' request, of a portion of the 5.75% convertible debentures as well as to the DRIP, partly offset by the purchase and cancellation of 1,190,173 shares under the Corporation's normal course issuer bid. The variation in the number of convertible debentures during the year is due to the issuance of 100,000 convertible debentures bearing interest at a rate of 4.25% and the redemption or conversion of 80,500 convertible debentures bearing interest at a rate of 5.75%. LIQUIDITY AND CAPITAL RESOURCES For the year ended December 31, 2015, the Corporation generated cash flows from operating activities of $4.6 million, compared with generating $87.7 million for the same period last year. During the year 2015, the Corporation generated funds from financing activities of $535.7 million and used funds for investing activities of $554.8 million, mainly to pay for the construction of its Development Projects. As at December 31, 2015, the Corporation had cash and cash equivalents amounting to $40.7 million, compared with $54.6 million as at December 31, Cash Flows from Operating Activities For the year ended December 31, 2015, cash flows generated by operating activities totalled $4.6 million ($87.7 million generated in 2014). The change is attributable mainly to the $119.6 million realized loss on derivative financial instruments, which more than offset the increase in revenues. This loss was financed from the project-level debts raised during the year. Cash Flows from Financing Activities For the year ended December 31, 2015, cash flows generated by financing activities totalled $535.7 million ($201.0 million generated in 2014). The cash-flows from the financing activities are attributable mainly to a $563.0 million net increase in longterm debt reflecting mainly the addition of the Development Projects-level debts and the repayment of long-term debt (including the revolving term credit facility) and to net proceeds of $95.5 million from the issuance of convertible debentures bearing interest at 4.25% partly offset by the $41.6 million redemption of outstanding convertible debentures bearing interest at 5.75% and by the $12.3 million purchase for cancellation of common shares under the Corporation's normal course issuer bid. Innergex Renewable Energy Inc Financial Review - 27

29 MANAGEMENT'S DISCUSSION AND ANALYSIS Use of Financing Proceeds Year ended December Proceeds from issuance of long-term debt 1,241, ,901 Repayment of long-term debt (including revolving term credit facility) (665,085) (120,590) Payment of deferred financing costs (13,842) (2,580) Sub-total: net increase in long-term debt 563, ,731 Net proceeds from issuance of convertible debentures 95,527 Proceeds from exercise of share options 394 Generation of financing proceeds 658, ,731 Payment of redemption of convertible debentures (41,591) Payment of buyback of common shares (12,349) Payment of other liabilities (244) (361) Payment of issuance cost of common and preferred shares (82) Business acquisitions (38,368) Realized loss on derivative financial instruments (119,557) (8,366) (Increase) in restricted cash and short-term investments (226,913) (36,062) Net funds (invested into) withdrawn from the reserve accounts (1,336) 6,538 Additions to property, plant and equipment (296,153) (205,460) Additions to project development costs (29,107) (24,955) Withdrawals from joint ventures 2,259 (Additions to) reductions of other long-term assets (1,324) 27,480 Net use of financing proceeds (728,574) (277,377) Reduction in working capital (69,629) (20,646) During the year ended December 31, 2015, the Corporation borrowed $1,242.0 million mainly to pay for construction of the Development Projects, the reduction in drawings under the revolving term credit facility and the $119.6 million realized loss on derivative financial instruments resulting from the settlement of the Boulder Creek, Upper Lillooet River, Big Silver Creek and Mesgi'g Ugju's'n bond forward contracts. It also increased restricted cash by $226.9 million, as the use of cash to pay for construction costs related to the Development Projects was more than offset by the addition of proceeds received from these projects' debts. During the corresponding period of 2014, the Corporation borrowed $379.9 million to pay for the construction of the Tretheway Creek, Boulder Creek, Upper Lillooet River and Big Silver Creek projects, for the pre-construction development of the Mesgi'g Ugju's'n project and for the acquisition of the SM-1 hydroelectric facility and to repay long-term debt; it also increased restricted cash by $36.1 million, as use of cash to pay for construction costs related to the Kwoiek Creek and Northwest Stave River facilities was more than offset by the addition $49.1 million corresponding to the unused proceeds from the Tretheway Creek project financing. Cash Flows from Investing Activities For the year ended December 31, 2015, cash flows used by investing activities amounted to $554.8 million ($268.4 million in 2014). During this period, additions to property, plant and equipment accounted for a $296.2 million outflow ($205.5 million outflow in 2014), an increase in restricted cash and short-term investments accounted for a $226.9 million outflow ($36.1 million outflow in 2014), additions to project development costs accounted for a $29.1 million outflow ($25.0 million outflow in 2014) and investments in reserve accounts accounted for a $1.3 million outflow ($6.5 million inflow in 2014). For the year ended December 31, 2014, these items were partly offset by a decrease in other long-term assets, which accounted for a $27.5 million inflow due mainly to the reimbursement of a loan by the seller of the SM-1 hydroelectric facility. Cash and Cash Equivalents For the year ended December 31, 2015, cash and cash equivalents decreased by $13.9 million (increased by $20.3 million in 2014) as a net result of its operating, financing and investing activities. As at December 31, 2015, the Corporation had cash and cash equivalents amounting to $40.7 million ($54.6 million as at December 31, 2014). Innergex Renewable Energy Inc Financial Review - 28

30 MANAGEMENT'S DISCUSSION AND ANALYSIS DIVIDENDS The following dividends were declared by the Corporation: Year ended December Dividends declared on common shares 1 63,646 59,549 Dividends declared on common shares ($/share) Dividends declared on Series A Preferred Shares 4,250 4,250 Dividends declared on Series A Preferred Shares ($/share) Dividends declared on Series C Preferred Shares 2,875 2,875 Dividends declared on Series C Preferred Shares ($/share) On February 24, 2015, the Board of Directors increased the annual dividend from $0.60 to $0.62 per common share, payable quarterly. The increase in dividends declared on common shares is also attributable to the issuance of 4,027,051 new common shares to pay for the acquisition of the SM-1 hydroelectric facility and the issuance of 3,653,422 new common shares upon conversion, at the holders' request, of convertible debentures bearing interest at 5.75%. The following dividends will be paid by the Corporation on April 15, 2016: Date of announcement Record date Payment date Dividend per common share ($) Dividend per Series A Preferred Share ($) 1 Dividend per Series C Preferred Share ($) 02/24/2016 3/31/2016 4/15/ On January 15, 2016 and on January 15 every five years thereafter, the holders of Preferred Shares, Series A (the "Series A Shares") have the right, at their option, to convert all or part of their Series A Shares into Series B, Preferred Shares (the "Series B Shares") of the Corporation, if certain conditions are met. After considering all election notices received by the conversion deadline of December 31, 2015 and the conversion requirements for, the holders of the Series A Shares were not entitled to convert their shares. Accordingly, 3,400,000 Series A Shares remain listed on the Toronto Stock Exchange (TSX) under the symbol INE.PR.A. The dividend rate for the five-year period commencing on January 15, 2016, and extending to but excluding January 15, 2021, will be 3.608% or $ per share per quarter. On February 24, 2016, the Board of Directors increased the annual dividend that the Corporation intends to distribute from $0.62 to $0.64 per common share, payable quarterly. FINANCIAL POSITION As at December 31, 2015, the Corporation had $3,128 million in total assets, $2,657 million in total liabilities, including $2,215 million in long-term debt, and $471.6 million in shareholders' equity. Also as at December 31, 2015, the Corporation had a working capital ratio of 2.15:1.00 (0.91:1.00 as at December 31, 2014). In addition to cash and cash equivalents amounting to $40.7 million, the Corporation had restricted cash and short-term investments of $312.7 million and reserve accounts of $42.8 million. The explanations below highlight the most significant changes in statement of financial position items during the year ended December 31, Innergex Renewable Energy Inc Financial Review - 29

31 MANAGEMENT'S DISCUSSION AND ANALYSIS Assets Highlights of significant changes in total assets during the year ended December 31, 2015 A $213.0 million net increase in cash and cash equivalents and restricted cash and short-term investments, due mainly to the addition of a portion or all of the financing received from the Boulder Creek, Upper Lillooet River, Big Silver Creek and Mesgi'g Ugju's'n project-level debts, which more than offset the amounts drawn to pay for construction of the Development Projects and the Tretheway Creek facility; A $278.4 million increase in property, plant and equipment, due mainly to construction of the Tretheway, Boulder Creek, Upper Lillooet River and Big Silver Creek projects and to the transfer of the Mesgi'g Ugju's'n project into property, plant and equipment, partly offset by the depreciation for the year and by a $6.6 million subsequent adjustment pertaining to purchase price allocation for the SM-1 hydroelectric facility out of property, plant and equipment and into intangible assets; A $15.0 million decrease in intangible assets, due mainly to amortization for the year, partly offset by a $6.6 million subsequent adjustment pertaining to purchase price allocation for the SM-1 hydroelectric facility into intangible assets from property, plant and equipment; and A $61.0 million decrease in project development costs, due mainly to the transfer of the Mesgi'g Ugju's'n project from project development costs and into property, plant and equipment since construction began in May and to the $51.7 million impairment amount recognized by the Corporation in relation to project development costs recorded following the Cloudworks Energy Inc. acquisition in Working Capital Items Working capital was positive at $212.2 million, as at December 31, 2015, with a working capital ratio of 2.15:1.00. As at December 31, 2014, working capital was negative at $17.4 million with a working capital ratio of 0.91:1.00. The increase in the working capital ratio over fiscal 2015 is due mainly to a $226.9 million increase in restricted cash and short-term investments and a $88.8 million decrease in the current liability portion of derivative financial instruments, which are explained separately below. These items were partly offset by a $49.9 million increase in accounts payable and a $21.2 million increase in current portion of long-term debt, also explained separately below. The Corporation considers its current level of working capital to be sufficient to meet its needs. The Corporation can also use its $425.0 million revolving term credit facility, if necessary. As at December 31, 2015, the Corporation had drawn $129.9 million and US$13.9 million as cash advances, while $95.5 million had been used for issuing letters of credit. Restricted cash and short-term investments amounted to $312.7 million as at December 31, 2015, of which $6.8 million was related to the Harrison Hydro L.P., $0.7 million to the Kwoiek Creek loan, $0.4 million to the Northwest Stave River loan, $20.6 million to the Tretheway Creek loan, $177.7 million to the Boulder Creek and Upper Lillooet River loan, $11.2 million to the Big Silver Creek loan and $95.3 million to the Mesgi'g Ugju's'n loan (compared with $85.8 million as at December 31, 2014, of which $6.7 million was related to the Harrison Hydro L.P., $23.5 million to the Kwoiek Creek loan, $6.5 million to the Northwest Stave River loan and $49.1 million to the Tretheway Creek loan). The increase stems mainly from the addition of a portion or all of the financing from the Boulder Creek, Upper Lillooet River, Big Silver Creek and the Mesgi'g Ugju's'n loans, which more than offset the amounts drawn to pay for construction of the Development Projects. The remainder of the Boulder Creek, Upper Lillooet River and the Mesgi'g Ugju's'n loans will be received in monthly installments. Accounts receivable increased from $35.3 million as at December 31, 2014, to $37.1 million as at December 31, 2015, due mainly to commodity taxes receivable from the construction of the Development Projects. Accounts payable and other payables increased from $45.6 million as at December 31, 2014, to $95.5 million as at December 31, 2015, due mainly to construction activities related to the Development Projects. Derivative financial instruments included in current liabilities decreased from $104.1 million as at December 31, 2014, to $15.3 million as at December 31, 2015, due mainly to the settlement in bond forward contracts entered into to hedge the interest rate on future project-level financing for the Development Projects following the close of the Boulder Creek, Upper Lillooet River, Big Silver Creek and Mesgi'g Ugju's'n project financings. Innergex Renewable Energy Inc Financial Review - 30

32 MANAGEMENT'S DISCUSSION AND ANALYSIS Reserve Accounts Reserve accounts consist of a hydrology/wind reserve, established at the start of commercial operation at a facility to compensate for the variability of cash flows related to fluctuations in hydrology or wind regime and to other unpredictable events, and a major maintenance reserve, established in order to prefund any major plant repairs that may be required to maintain the Corporation's generating capacity. The Corporation had $41.5 million in long-term reserve accounts as at December 31, 2015, compared with $40.7 million as at December 31, The increase stems mainly from the reserves for the Kwoiek Creek facility put in place in The availability of funds in the hydrology/wind and major maintenance reserve accounts are in large part restricted by credit agreements. Property, Plant and Equipment Property, plant and equipment are comprised mainly of hydroelectric facilities, wind farms and a solar farm that are either in operation or under construction. They are recorded at cost less accumulated depreciation and accumulated impairment losses, if any. The Corporation had $2,174 million in property, plant and equipment as at December 31, 2015, compared with $1,896 million as at December 31, The increase stems mainly from the construction of the Development Projects and to the transfer of the Mesgi'g Ugju's'n project into property, plant and equipment, partly offset by the depreciation for the year and by a $6.6 million subsequent adjustment pertaining to purchase price allocation for the SM-1 hydroelectric facility out of property, plant and equipment and into intangible assets. Intangible Assets Intangible assets consist of various power purchase agreements, permits and licenses. They also include the extended warranty for the Montagne Sèche and Gros-Morne wind farm turbines. The Corporation had $472.3 million in intangible assets as at December 31, 2015, compared with $487.3 million as at December 31, The decrease is due mainly to amortization, partly offset by a $6.6 million subsequent adjustment pertaining to purchase price allocation for the SM-1 hydroelectric facility into intangible assets from property, plant and equipment. Project Development Costs Project development costs are the costs to acquire and establish Development Projects and to acquire Prospective Projects. Depending on their nature, these costs are transferred either to property, plant and equipment or to intangible assets once the project reaches the construction phase. The Corporation's project development costs were nil as at December 31, 2015, compared with $61.0 million as at December 31, The decrease stems from the transfer of the Mesgi'g Ugju's'n project from project development costs and into property, plant and equipment since construction of the project began in last May and, although it retains ownership of the licenses, the recognition by the Corporation of a $51.7 million impairment amount in relation to project development costs recorded toward future development in British Columbia following the Cloudworks Energy Inc. acquisition in Investments in Joint Ventures Investments in joint ventures represent the Corporation's ownership portion of joint ventures, which are accounted for using the equity method. As at December 31, 2015, the Corporation had $9.3 million in investments in joint ventures, compared with $14.5 million as at December 31, This $5.2 million decrease reflects $6.9 million in distributions ($3.1 million from Umbata Falls and $3.8 million from Viger-Denonville) made by the joint ventures to the Corporation during the year, partly offset by the recognition of $1.7 million in net earnings. Please refer to the "Investments in Joint Ventures" section for more information. Liabilities and Shareholders' Equity Derivative Financial Instruments and Risk Management The Corporation uses derivative financial instruments ("Derivatives") to manage its exposure to the risk of increasing interest rates on its debt financing and its exposure to the risk of rising foreign currencies on its equipment purchases. The Corporation does not own or issue any Derivatives for speculation purposes. Since October 2014, the Corporation has used hedge accounting in the treatment of new Derivatives, and since April 1, 2015, has also adopted hedge accounting in the treatment of existing Derivatives used to fix the interest rate on the project-level debts (with the exception of that of Umbata Falls) and on most of its revolving term credit facility in order to reduce fluctuations in net earnings or losses resulting from unrealized gains or losses on these Derivatives during a given period. Under hedge accounting, most of the unrealized gains or losses on Derivatives that arise from a decrease or increase in the benchmark interest rate will be recorded in other comprehensive income, while only the portion of the unrealized gain or loss related to the "ineffectiveness" and the settlement of the Derivatives will be recorded in net earnings. Innergex Renewable Energy Inc Financial Review - 31

33 MANAGEMENT'S DISCUSSION AND ANALYSIS Interest rate swap contracts allow the Corporation to eliminate the risk of interest rate increases in actual floating-rate debts. These totalled $632.6 million as at December 31, Consequently, as at December 31, 2015, interest rate swaps related to outstanding debts combined with the $1,521 million in existing fixed-rate debts and $93.4 million in convertible debentures mean that 99% of outstanding debts are protected from interest rate increases. Bond forward contracts allow the Corporation to eliminate the risk of interest rate increases in planned long-term debt that it will need to secure for its Development Projects. Upon closing the fixed-rate or interest-swapped long-term financing, the Corporation will settle the corresponding derivative financial instruments, which will result in a realized gain or loss on derivative financial instruments. These gains or losses will serve to offset a higher or lower interest rate on the project-level debt. In March 2015, the Corporation announced the closing of a $491.6 million financing for the Boulder Creek and Upper Lillooet River hydroelectric projects. The concurrent settlement of the Boulder Creek and Upper Lillooet River bond forward contracts gave rise to a $68.0 million realized loss on derivative financial instruments. This loss results from a decrease in benchmark interest rates between the date the bond forwards were entered into (between September and December 2013) and the settlement date (March 17, 2015) and will be compensated for by the low weighted average fixed interest rate of 4.36% for these 25- to 40-year term loans. In June 2015, the Corporation closed a $197.2 million financing for the Big Silver Creek hydroelectric project. The concurrent settlement of the Big Silver Creek bond forward contracts gave rise to a $24.7 million realized loss on derivative financial instruments. This loss results from a decrease in benchmark interest rates between the date the bond forwards were entered into (between December 2013 and January 2014) and the settlement date (June 22, 2015) and will be compensated for by the low weighted average fixed interest rate of 4.71% for these 25- to 40-year term loans. In September 2015, the Corporation announced the closing of a $311.7 million financing for the Mesgi'g Ugju's'n wind project. The concurrent settlement of the Mesgi'g Ugju's'n bond forward contracts gave rise to a $27.0 million realized loss on derivative financial instruments. This loss results from a decrease in benchmark interest rates between the date the bond forwards were entered into (in March 2014) and the settlement date (September 28, 2015) and will be compensated for by the low weighted average fixed interest rate of 4.18% for these 9.5- to 19.5-year term loans. As at December 31, 2015, and as at the date of this MD&A, the Corporation had secured the project financing for all of its existing Development Projects and had no outstanding bond forward contracts ($535.0 million for the Upper Lillooet River, Boulder Creek, Big Silver Creek and Mesgi'g Ugju's'n Development projects as at December 31, 2014). As at the date of this MD&A, the Corporation had no euro foreign exchange forward contracts outstanding ($78.4 million at December 31, 2014), as the foreign exchange forward contract it had entered into to eliminate the risk of a euro appreciation versus the Canadian dollar on equipment purchases for the Mesgi'g Ugju's'n project was settled upon maturity and the exchange rate for the euro portion of the turbine supply contract was fixed, eliminating any further euro exposure. Overall, Derivatives had a net negative value of $67.7 million at December 31, 2015 (negative $145.8 million at December 31, 2014). The decrease is due mainly to the settlement of the Boulder Creek, Upper Lillooet River, Big Silver Creek and Mesgi'g Ugju's'n bond forward contracts. These figures exclude the impact of Derivatives used to hedge loans of the Corporation's joint ventures. For information on the impact of derivative financial instruments used in the Corporation's joint ventures, please refer to the "Investments in Joint Ventures" section. Innergex Renewable Energy Inc Financial Review - 32

34 MANAGEMENT'S DISCUSSION AND ANALYSIS Outstanding Interest Rate Derivative FInancial Instruments Maturity Early termination option December 31, 2015 December 31, 2014 Contracts for which hedge accounting has been applied since: October 16, 2014 Interest rate swaps, 2.33% ,000 20,000 December 15, 2014 Interest rate swaps, 2.30% ,000 20,000 April 1, 2015 Interest rate swaps, 4.27% to 4.41% 2018 None 82,600 82,600 Interest rate swaps, 2.94% to 4.83%, amortizing 2026 None 46,342 49,718 Interest rate swaps, from 3.35% to 3.50%, amortizing 2027 None 35,080 37,506 Interest rate swap, 3.74%, amortizing 2030 None 89,113 93,511 Interest rate swap, 4.22%, amortizing ,063 27,485 Interest rate swap, 4.25%, amortizing ,146 43,360 Interest rate swap, 4.61%, amortizing , ,463 Interest rate swap, 2.85%, amortizing ,018 19,313 September 28, 2015 Interest rate swap, 0.96%, amortizing 2017 None 49,250 Interest rate swap, 1.91%, amortizing 2026 None 103,000 Contracts for which hedge accounting is not used: Bond forwards, from 2.74% to 3.32% 2015 None 535,000 Interest rate swap, 3.96% to 4.09% 2015 None 15,000 Interest rate swap, 4.27% 2016 None 3,000 3,000 Total 632,569 1,046,956 Accrual for Acquisition of Long-Term Assets Accrual for acquisition of long-term assets consists of long-term debt commitments that have been secured and will be drawn to finance the Corporation's projects currently under construction or under development. As at December 31, 2015, accrual for acquisition of long-term assets was nil ($25.3 million as at December 31, 2014). The $25.3 million decrease results from payments made in relation to the construction of the Development Projects and the amounts borrowed for the construction of the projects. Long-Term Debt As at December 31, 2015, long-term debt totalled $2,215 million ($1,645 million as at December 31, 2014). The $570.8 million increase results mainly from the addition of the Boulder Creek and Upper Lillooet River debts in the amount of $445.7 million out of the $491.6 million project financing closed on March 17, the addition of the Big Silver Creek project financing closed on June 22 in the amount of $197.2 million and from the addition of the Mesgi'g Ugju's'n debt in the amount of $159.5 million out of the $311.7 million project financing closed on September 28. This increase was partly offset by the scheduled repayment of project-level debts and the reduction of drawings under the revolving term credit facility using the proceeds of the issuance of convertible debentures bearing interest at 4.25% as well as a portion of the proceeds of the Boulder Creek, Upper Lillooet River and Big Silver Creek financings to reimburse the excess equity invested in the projects by the Corporation. Innergex Renewable Energy Inc Financial Review - 33

35 MANAGEMENT'S DISCUSSION AND ANALYSIS Since the beginning of the 2015 fiscal year, the Corporation and its subsidiaries have met all the financial and non-financial conditions related to their credit agreements, trust indentures and PPAs. Were they not met, certain financial and non-financial covenants included in the credit agreements or trust indentures entered into by various subsidiaries of the Corporation could limit the capacity of these subsidiaries to transfer funds to the Corporation. These restrictions could have a negative impact on the Corporation's ability to meet its obligations. Revolving credit term facility (with recourse to the Corporation) Effective allin interest rate after accounting for the interest rates swaps Maturity December 31, 2015 December 31, 2014 a) Prime rate advances 3.30% a) Bankers acceptances 5.50% , ,880 a) LIBOR advances, US$13, % ,238 16,125 Term loans (Non-recourse to the Corporation) 149, ,025 b) Harrison Operating Facilities, non-interest bearing term loans from partners ,750 c) Hydro-Windsor, fixed rate term loan 8.25% ,015 2,145 d) Fitzsimmons Creek, floating-rate term loan 3.98% ,051 21,430 e) Magpie, fixed rate bridge loan 2.33% e) Magpie, fixed rate debenture 4.59% ,094 f) Montagne-Sèche, floating-rate term loan 5.97% ,063 27,485 g) Rutherford Creek, fixed rate term loan 6.88% ,378 42,677 e) Magpie, fixed rate convertible debenture 4.34% ,020 5,262 h) Ashlu Creek, floating-rate term loan 6.06% ,062 96,695 i) Sainte-Marguerite, fixed rate term loan 3.30% ,598 35,899 j) L Anse-à-Valleau, floating-rate term loan 6.03% ,091 38,716 k) Carleton, floating-rate term loan 5.46% ,758 48,997 l) Stardale, floating-rate term loan 5.99% , ,643 e) Magpie, fixed rate term loan 4.37% ,243 54,452 m) Kwoiek Creek, fixed rate term loan 5.08% , ,500 n) Northwest Stave River, fixed rate term loan 5.30% ,972 71,972 m) Kwoiek Creek, fixed rate term loan 10.07% ,662 3,662 o) Tretheway, fixed rate construction loan 4.99% 92,916 92,916 p) Mesgi'g Ugju's'n, fixed rate construction loan 4.28% 159,459 q) Boulder and Upper Lillooet, fixed rate construction loan 4.22% 172,207 r) Big Silver, fixed rate construction loan 4.57% 51,012 q) Boulder and Upper Lillooet, fixed rate construction loan 4.46% 227,938 q) Boulder and Upper Lillooet, fixed rate construction loan 4.46% 45,588 r) Big Silver, fixed rate construction loan 4.76% 128,311 r) Big Silver, fixed rate construction loan 4.76% 17,900 i) Sainte-Marguerite, fixed rate debenture 8.00% ,401 42,401 Other loans with various maturities and interest rates ,634, ,682 Innergex Renewable Energy Inc Financial Review - 34

36 MANAGEMENT'S DISCUSSION AND ANALYSIS Effective allin interest rate after accounting for the interest rates swaps Maturity December 31, 2015 December 31, 2014 Bonds (Non-recourse to the Corporation) s) Harrison Hydro L.P.'s facilities, real return 3.95% , ,014 t) Harrison Hydro L.P.'s facilities, fixed rate 6.61% , ,485 u) Harrison Hydro L.P.'s facilities, real return 5.02% ,222 27, , ,319 Total long-term debt 2,242,318 1,659,026 Deferred financing costs (26,885) (14,427) 2,215,433 1,644,599 Current portion of long-term debt ( net of $29 deferred financing costs in 2015, nil in 2014) (54,995) (33,799) Long-term portion of long-term debt 2,160,438 1,610,800 Explanatory notes: a. Revolving term credit facility The Corporation has a maximum borrowing capacity of $425.0 million on its revolving term credit facility, which will mature in As at December 31, 2015, the Bankers' Acceptances ( BA ) rate advances and prime rate advances totaling $129.9 million along with a LIBOR rate advance of $19.2 million (US$13.9 million) were due under this facility. An amount of $95.5 million has been used to secure letters of credit. Thus, the unused and available position of the facility was $180.4 million. The carrying value of assets of the Corporation and subsidiaries given as securities under this facility totals approximately $473.1 million. The revolving term credit facility was renegociated on January 18, 2016, see subsequent events section. b. Harrison Operating Facilities, term loans The non-interest bearing loans from the partners of the Corporation in the Harrison Project were repaid in full in c. Hydro-Windsor The loan consists of a 20-year term loan starting in December 1996 and amortized over a 20-year period ending in December The loan is repayable by monthly blended payments of principal and interest totaling $0.1 million. The principal repayments for 2016 are set at $1.0 million. The loan is secured by the assets of Hydro-Windsor L.P. with a carrying value of approximately $10.0 million. d. Fitzsimmons Creek The loan consists of a five-year term loan starting in December 2011 and amortized over a 30-year period. The loan advances bear interest at the BA rate plus an applicable margin. The principal repayments are variable and are set at $19.0 million for As at December 31, 2015, the all-in effective interest rate was 3.98% (3.98% in 2014) after accounting for the interest rate swap. The lenders also agreed to make available a letter of credit facility in an amount not to exceed $150. As at December 31, 2015, an amount of $50 had been used to secure one letter of credit. This debt is secured by the assets of Fitzsimmons Creek Hydro L.P. with a carrying value of approximately $25.0 million. Innergex Renewable Energy Inc Financial Review - 35

37 MANAGEMENT'S DISCUSSION AND ANALYSIS e. Magpie The bridge loan is amortized until August The bridge loan is repayable in monthly blended payments of principal and interest totaling $27. The principal repayments for the bridge loan are set at $0.3 million for The debenture is amortized until December The debenture is repayable by yearly blended payments of principal and interest totaling $0.4 million, excluding non-cash implicit interest of $35. The principal repayment for 2016 is set at $0.4 million. The convertible debenture has no predetermined repayment schedule and matures in January The convertible debenture entitles the municipality to a 30% interest in the facility upon conversion of the debenture on or before January 1, Early conversion is at the discretion of the Corporation. The term loan amortizing until 2031 is repayable in monthly blended payments of principal and interest totaling $0.4 million. The principal repayments for the term loan are variable and are set at $1.7 million for 2016; The bridge loan and the term loan are secured by the assets of Magpie L.P. with a carrying value of approximately $99.7 million. f. Montagne-Sèche In May 2014, the Corporation renegotiated the loan to extend the maturity to June The loan consists of a 7-year term loan, amortized over a 16-year period starting in May As at December 31, 2015, the loan bears interest at the BA rate plus an applicable margin. The principal repayments are variable and set at $1.5 million for As at December 31, 2015, the all-in effective interest rate was 5.97% (5.97% in 2014) after accounting for the interest rate swap. The lenders also agreed to make available a letter of credit facility in an amount not to exceed $0.4 million. As at December 31, 2015, an amount of $0.3 million has been used to secure one letter of credit. The loan is secured by the assets of Innergex Montagne-Sèche, L.P. with a carrying value of approximately $36.5 million. g. Rutherford Creek The loan consists of a 20-year fixed rate term loan starting in July 2004 amortized over a 12-year period effective July 1, This debt is repayable by monthly blended payments of principal and interest totaling $0.5 million. The principal repayments are variable and are set at $3.5 million for The loan is secured by the assets of Rutherford Creek Power Limited Partnership, with a carrying value of approximately $81.5 million. h. Ashlu Creek The loan consists of a 15-year term loan, amortized over a 25-year period starting in September The loan bears interest at the BA rate plus an applicable margin. The term loan is repayable in quarterly installments. The principal repayments are variable and are set at $3.3 million for As at December 31, 2015, the all-in effective interest rate was 6.06% (6.16% in 2014) after accounting for the interest rate swap. The lenders also agreed to make available a letter of credit facility in an amount not to exceed $3.0 million. As at December 31, 2015, an amount of $1.5 million had been used to secure one letter of credit. The loan is secured by the assets of Ashlu Creek hydroelectric facility with a carrying value of approximately $164.3 million. i. Sainte-Marguerite As part of the Sainte-Marguerite Acquisition, the Corporation assumed a $30.8 million term loan, bearing interest at 7.40%, repayable in monthly blended payments of principal and interest totaling $0.4 million, increasing over the years and maturing in The principal repayments for 2016 are set at $2.6 million. The term loan was accounted for at its fair market value of $37.5 million for an effective rate of 3.30%. The loan is secured by the assets of Sainte-Marguerite L.P. with a carrying value of approximately $136.3 million. Innergex Renewable Energy Inc Financial Review - 36

38 MANAGEMENT'S DISCUSSION AND ANALYSIS Concurrent with the acquisition of the Sainte-Marguerite facility, a debenture was issued by Sainte-Marguerite L.P. to Desjardins Group Pension Plan for total proceeds of $40.9 million. In December 2014, an additional $1.5 million was subscribed to the debenture issued by Sainte-Marguerite L.P. for a total amount of $42.4 million. This debenture carries an interest rate of 8.00%; it has no predetermined repayment schedule and matures in j. L'Anse-à-Valleau The loan consists of an 18.5-year term loan starting in December 2007 and amortized over an 18.5-year period. The loan bears interests at the BA rate plus an applicable margin. The term loan is repayable in quarterly installments. The principal repayments are variable and are set at $2.8 million for As at December 31, 2015, the all-in effective interest rate was 6.03% (6.03% in 2014) after accounting for the interest rate swap. The lenders also agreed to make available a credit facility of $1.2 million in order to secure letters of credit. As at December 31, 2015, an amount of $0.4 million had been used to secure one letter of credit. The loan is secured by the assets of Innergex AAV, L.P. with a carrying value of approximately $58.0 million. k. Carleton The loan consists of a 14-year term loan starting in June 2013 and amortized over a 14-year period. The term loan bears interest at the BA rate plus an applicable margin. The term loan is repayable in quarterly installments. The principal repayments are variable and are set at $3.4 million for As at December 31, 2015, the all-in effective interest rate was 5.46% (5.46% in 2014) after accounting for the interest rate swap. This debt is secured by the assets of Innergex CAR, L.P. with a carrying value of approximately $74.3 million. l. Stardale The loan consists of an 18-year term loan starting in September 2012 and amortized over an 18-year period. The loan bears interest at the BA rate plus an applicable credit margin. The term loan is repayable in quarterly installments. The principal repayments are variable and set at $5.0 million for As at December 31, 2015, the all-in effective interest rate was 5.99% (5.99% in 2014) after accounting for the interest rate swap. The lenders also agreed to make available a letter of credit facility in an amount not to exceed $5.6 million. As at December 31, 2015, an amount of $5.6 million had been used to secure two letters of credit. The loan is secured by the assets of Stardale L.P. with a carrying value of approximately $114.5 million. The loan was refinanced on February 22, 2016, see subsequent events section. m. Kwoiek Creek The construction term loan was converted into a 37-year term loan in February 2015 and amortized over a 36-year period starting in January The term loan is repayable in quarterly installments. The principal repayments are variable and set at nil for The loan is secured by the assets of Kwoiek Creek Resources L.P. with a carrying value of approximately $163.6 million. The Corporation's partner in the Kwoiek Creek project made a loan to Kwoiek Creek Resources Limited Partnership. Under the project agreements, both partners can participate in the project financing. n. Northwest Stave River The non-recourse construction loan was converted into a 38-year term loan in February 2015 and amortized over a 35-year period. The loan is secured by Northwest Stave River L.P.'s assets with a carrying value of approximately $82.1 million. o. Tretheway On September 30, 2014, the Corporation closed a $92.9 million non-recourse construction and term project financing for the Tretheway Creek run-of-river hydroelectric project. The construction loan carries a fixed interest rate of 4.99%; it will convert into a term loan in 2016 and the principal will begin to be amortized over a 35-year period, starting in the Innergex Renewable Energy Inc Financial Review - 37

39 MANAGEMENT'S DISCUSSION AND ANALYSIS fifth year following the commencement of delivery of electricity which took place on November 9, The loan is secured by the assets of Tretheway L.P. with a carrying value of approximately $124.1 million. p. Mesgig'g Ugju's'n On September 28, 2015, Mesgi g Ugju s n (MU) Wind Farm L.P. closed a $311.7 million non-recourse construction and term project financing for the Mesgi g Ugju s n wind project. The loan comprises three facilities or tranches: A $49.3 million floating-rate construction loan carrying a swap-fixed interest rate of 2.41%; following the start of the wind farm s commercial operation, it will be repaid with the proceeds of the scheduled reimbursement by Hydro-Québec for the Mesgi g Ugju s n electrical substation. As at December 31, 2015, this tranche was not used; A $103.0 million floating-rate construction loan carrying a swap-fixed interest rate of 3.54%; following the start of the wind farm s commercial operation, it will convert into a 9.5-year term loan and the principal will be amortized over the term of the loan. As at December 31, 2015, this tranche was not used; A $159.5 million construction loan carrying a fixed interest rate of 4.28%; following the start of the wind farm s commercial operation, it will convert into a 19.5-year term loan and the principal will begin to be amortized after the maturity of the 9.5-year term loan. As at December 31, 2015, this tranche was fully used. The lenders also agreed to make available a credit facility in an amount not to exceed $51.3 million. As at December 31, 2015, an amount of $31.6 million had been used to secure two letters of credit. This debt is secured by the assets of Mesgi g Ugju s n (MU) Wind Farm L.P. with a carrying value of approximately $192.5 million. q. Boulder Creek and Upper Lillooet River On March 17, 2015, Boulder Creek Power Limited Partnership and Upper Lillooet River Power Limited Partnership jointly closed a $491.6 million non-recourse construction and term project financing for the Boulder Creek and Upper Lillooet River run-of-river hydroelectric projects. The loan comprises three facilities or tranches: A $191.6 million construction loan carrying a fixed interest rate of 4.22%; following the start of the facilities commercial operation, it will convert into a 25-year term loan and the principal will be amortized over a 20-year period, starting in the sixth year. As at December 31, 2015, an amount of $172.2 million had been drawn from this tranche; A $250.0 million construction loan carrying a fixed interest rate of 4.46%; following the start of the facilities commercial operation, it will convert into a 40-year term loan and the principal will begin to be amortized after the 25-year term loan s maturity. As at December 31, 2015, an amount of $227.9 million had been drawn from this tranche; A $50.0 million construction loan carrying a fixed interest rate of 4.46%; following the start of the facilities commercial operation, it will convert into a 40-year term loan and its principal will be reimbursed at maturity. As at December 31, 2015, an amount of $45.6 million had been drawn from this tranche. This debt is secured by the assets of Boulder Creek Power L.P. and Upper Lillooet River Power L.P. with a carrying value of approximately $464.0 million. r. Big Silver Creek On June 22, 2015, Big Silver Creek Power Limited Partnership closed a $197.2 million non-recourse construction and term project financing for the Big Silver Creek River run-of-river hydroelectric project. The loan comprises three facilities or tranches: A $51.0 million construction loan carrying a fixed interest rate of 4.57%; following the start of the facilities commercial operation, it will convert into a 25-year term loan and the principal will begin to be amortized over an 18-year period starting in the seventh year; A $128.3 million construction loan carrying a fixed interest rate of 4.76%; following the start of the facilities commercial operation, it will convert into a 40-year term loan and the principal will be amortized after the 25-year term loan reaches maturity; Innergex Renewable Energy Inc Financial Review - 38

40 MANAGEMENT'S DISCUSSION AND ANALYSIS A $17.9 million construction loan carrying a fixed interest rate of 4.76%; following the start of the facilities commercial operation, it will convert into a 40-year term loan and its principal will be reimbursed at maturity. This debt is secured by the assets of Big Silver Creek Power L.P. with a carrying value of approximately $190.7 million. s. Harrison Operating Facilities, Senior Real Return bond The Harrison Operating Facilities Senior Real Return bond bears interest at 2.96% adjusted by an inflation ratio as well as an inflation compensation interest factor. Both inflation adjustments are based on the All-items Consumer Price Index for Canada ( CPI ), which is not seasonally adjusted. Payments on this bond are due semi-annually and the bond matures in June Semi-annual payments are $5.8 million before CPI adjustment ($6.6 million including CPI adjustment in 2015). In December 2031, the payment amount decreases to $4.5 million before CPI adjustment, where it remains until maturity. For 2016, the principal repayments are set at $5.8 million. The bond is secured by the Harrison Operating Facilities. t. Harrison Operating Facilities, Senior Fixed Rate bond The Harrison Operating Facilities Senior Fixed Rate bond bears interest at 6.61%. Payments on this bond are due semiannually with the bond maturing in September Semi-annual payments amount to $8.1 million. In September 2031, the payment amount decreases to $6.7 million, where it remains until maturity. For 2016, the principal repayments are set at $3.3 million. The bond is secured by the Harrison Operating Facilities. u. Harrison Operating Facilities, Junior Real Return bond The Harrison Operating Facilities Junior Real Return Rate bond bears interest at 4.27% adjusted by an inflation ratio and an inflation compensation interest factor. Both inflation adjustments are based on the CPI, which is not seasonally adjusted. Payments on this bond are due quarterly and the bond matures in September Quarterly interest payments amount to $0.3 million before CPI adjustment ($0.3 million including CPI adjustment in 2015). In June 2017, the payment amount increases to $0.4 million before CPI adjustment, where it remains until maturity. Principal repayment does not commence until June The bond is secured by the Harrison Operating Facilities. Convertible debentures In 2015, the Corporation redeemed $41.6 million and converted $38.9 million of the convertible debentures bearing interest at 5.75% into 3,653,422 Innergex common shares pursuant to the issuance of a notice of redemption. The Corporation also issued subordinate unsecured convertible debentures bearing interest at a rate of 4.25% for a total amount of $100.0 million. The net proceeds of $95.5 million were used to reduce drawings under the revolving term credit facility; the funds available under this facility were used to redeem the outstanding convertible debentures bearing interest at 5.75%. As at December 31, 2015, the liability portion of convertible debentures stood at $93.4 million and the equity portion stood at $1.9 million ($80.0 million and $1.3 million as at December 31, 2014). The convertible debentures currently outstanding bear interest at a rate of 4.25% per annum, payable semi-annually on August 31 and February 28 of each year, commencing on February 28, They are convertible at the holder s option into common shares of the Corporation at a conversion price of $15.00 per share, representing a conversion rate of common shares per each $1,000 of principal amount of convertible debentures. They will mature on August 31, 2020, and will not be redeemable before August 31, 2018, except in certain limited circumstances. The convertible debentures are subordinated to all other indebtedness of the Corporation. Preferred Shares On September 14, 2010, the Corporation issued a total of 3,400,000 Series A Preferred Shares at $25.00 per share for aggregate gross proceeds of $85.0 million. The holders of Series A Preferred Shares are entitled to receive fixed cumulative preferential cash dividends, as and when declared by the Board of Directors. The dividends are payable quarterly on the 15th day of January, April, July and October in each year. For the initial five-year period to, but excluding January 15, 2016 (the Initial Fixed Rate Period ), the dividends were payable at an annual rate equal to $1.25 per share. The annual dividend rate for the five-year period starting January 15, 2016, equal $0.902 per share. Innergex Renewable Energy Inc Financial Review - 39

41 MANAGEMENT'S DISCUSSION AND ANALYSIS For each five-year period after the Initial Fixed Rate Period (each a Subsequent Fixed Rate Period ), the holders of the Series A Preferred Shares will be entitled to receive fixed cumulative preferential cash dividends as and when declared by the Board of Directors. The dividends will be payable quarterly in an annual amount per Series A Preferred Share equal to the sum of the yield on a Government of Canada bond with a five-year term to maturity on the applicable fixed rate calculation date, plus 2.79% applicable to such Subsequent Fixed Rate Period multiplied by $ Each holder of Series A Preferred Shares will have the right, at its option, to convert all or any of its Series A Preferred Shares into the Series B Preferred Shares of the Corporation on the basis of one Series B Preferred Share for each Series A Preferred Share converted, subject to certain conditions, on January 15, 2016, and on January 15 every five years thereafter. The holders of Series B Preferred Shares will be entitled to receive floating rate cumulative preferential cash dividends as and when declared by the Board of Directors. The dividends will be payable quarterly in an annual amount per Series B Preferred Share equal to the Treasury Bill rate for the preceding quarterly period plus 2.79% per annum determined on the 30th day prior to the first day of the applicable quarterly floating rate period multiplied by $ None of the Series A Preferred Shares were converted into Series B Preferred Shares on January 15, The Series A Preferred Shares were not redeemable by the Corporation prior to January 15, None were redeemed at that date. The next redemption date is January 15, 2021, and on January 15 every five years thereafter, at which time, the Corporation may, at its option, redeem all or any number of the outstanding Series A Preferred Shares. On December 11, 2012, the Corporation issued a total of 2,000,000 Series C Preferred Shares at $25.00 per share for aggregate gross proceeds of $50.0 million. Holders of the Series C Preferred Shares will be entitled to receive fixed cumulative preferential cash dividends as and when declared by the Corporation's Board of Directors. The dividends will be payable quarterly on the 15th day of January, April, July and October in each year at an annual rate equal to $ per share. The Series C Preferred Shares will not be redeemable by the Corporation prior to January 15, The Series C Preferred Shares do not have a fixed maturity date and are not redeemable at the option of the holders. The Series A Preferred Shares and the Series C Preferred Shares are rated P-3 by S&P. For more information about the Series A Preferred Shares, please refer to the Short Form Prospectus dated September 7, 2010, and for more information about the Series C Preferred Shares, please refer to the Short Form Prospectus dated December 4, 2012, both of which are available on Innergex's website at and on the SEDAR website at Shareholders' Equity As at December 31, 2015, the Corporation's shareholders' equity totalled $471.6 million, including $21.9 million of noncontrolling interests, compared with $562.2 million, including $47.4 million of non-controlling interests, as at December 31, This $90.7 million decrease in total shareholders' equity is attributable mainly to the $70.8 million in dividends declared on preferred and common shares, the recognition of a $48.4 million net loss and the $12.3 million purchase for cancellation of common shares under the Corporation's normal course issuer bid, partly offset by the issuance of 3,653,422 common shares at a price of $10.65 per share, upon conversion at the holders' request, of convertible debentures bearing interest at 5.75%. Contractual Obligations As at December 31, 2015 Total Under 1 year 1 to 3 years 4 to 5 years Thereafter Long-term debt including convertible debentures 2,386,806 53,537 73, ,635 1,932,366 Interest on long-term debt and convertible debentures 2,345, , , ,920 1,796,040 Others 16,822 1,914 2,441 1,618 10,849 Purchase (Contractual) obligations 1 397, ,388 4,514 4,427 39,269 Total contractual obligations 5,147, , , ,600 3,778, Purchase obligations are derived mainly from engineering, procurement and construction contracts. Contingencies The acquisition of Cloudworks Energy Inc. realized in 2011 provides for the potential payment of additional amounts to the vendors over a period commencing on the acquisition date and ending on the 40th anniversary of the last project under development to achieve commercial operation (or to April 4, 2061, if earlier). The deferred payments are effectively intended Innergex Renewable Energy Inc Financial Review - 40

42 MANAGEMENT'S DISCUSSION AND ANALYSIS to provide for a potential sharing of the value created if the projects perform better than the Corporation expects and would result in incremental accretion to the Corporation net of these payments. The maximum aggregate amount of all deferred payments under this acquisition was limited to a present value amount of $35.0 million as at the acquisition date. In the year ended December 31, 2015, the Corporation recognized an impairment related to its BC Prospective Projects acquired in Concurrently with the recognition of an impairment, the Corporation recorded a $3.4 million realized gain on contingent considerations in relation to amounts payable on the future development of the Prospective Projects in British Columbia acquired from Cloudworks Energy Inc. In connection with the Magpie Acquisition, the Corporation assumed an obligation to pay contingent consideration to the Minganie Regional County Municipality until the convertible debenture issued by Magpie Limited Partnership is converted. Upon conversion, the Minganie Regional County Municipality will be entitled to a participation of 30% in Magpie Limited Partnership. Off-Balance-Sheet Arrangements As at December 31, 2015, the Corporation had issued letters of credit totalling $139.1 million to meet its obligations under its various PPAs and other agreements. Of this amount, $95.5 million was issued under its revolving term credit facility, for the most part on a temporary basis during the construction of the Development Projects, with the remainder being issued under the projects' non-recourse credit facilities. As at that date, Innergex had also issued a total of $30.6 million in corporate guarantees used mainly to support the performance of the Brown Lake hydroelectric facility and the construction of the Mesgi'g Ugju's'n project. TRANSACTIONS BETWEEN RELATED PARTIES During the first quarter of 2015, Harrison Hydro L.P. reimbursed the $1.8 million non-interest bearing term loans made by its partners. FREE CASH FLOW AND PAYOUT RATIO Free Cash Flow When evaluating its operating results, a key performance indicator for the Corporation is the cash flows available for distribution to common shareholders and for reinvestment to fund the Corporation's growth. Free Cash Flow is a non-ifrs measure that the Corporation calculates as cash flows from operating activities before changes in non-cash operating working capital items, less maintenance capital expenditures net of proceeds from disposals, scheduled debt principal payments and preferred share dividends declared. It also subtracts the portion of Free Cash Flow attributed to non-controlling interests regardless of whether an actual distribution to non-controlling interests is made in order to reflect the fact that such distribution may not occur in the period the Free Cash Flow is generated, and adds back cash receipts by the Harrison Hydro L.P. for the wheeling services to be provided to other facilities owned by the Corporation over the course of their PPAs. The Corporation also adjusts for other elements that represent cash inflows or outflows that are not representative of the Corporation's long-term cash generating capacity. Such adjustments include adding back transaction costs related to realized acquisitions (which are financed at the time of the acquisition) and adding back realized losses or subtracting realized gains on derivative financial instruments used to hedge the interest rate on project-level debt prior to securing such debt or the exchange rate on equipment purchases. Innergex Renewable Energy Inc Financial Review - 41

43 MANAGEMENT'S DISCUSSION AND ANALYSIS Free Cash Flow and Payout Ratio calculation Trailing 12 months ended December Cash flows from operating activities 4,557 87, ,286 Add (Subtract) the following items: Changes in non-cash operating working capital items (8,275) 13,218 (30,283) Maintenance capital expenditures net of proceeds from disposals (3,553) (2,851) (2,441) Scheduled debt principal payments (31,813) (29,190) (26,520) Free Cash Flow attributed to non-controlling interests 1 (2,550) (4,865) (5,453) Dividends declared on Preferred shares (7,125) (7,125) (7,391) Cash receipt for wheeling services to be provided by the Harrison Hydro L.P. to other facilities 2 3,327 2,092 4,916 Adjust for the following elements: Transaction costs related to realized acquisitions Realized losses on derivative financial instruments 119,557 8,366 3,259 Free Cash Flow 74,386 67,744 58,982 Dividends declared on common shares 63,646 59,549 54,967 Payout Ratio - before the impact of the DRIP 86% 88% 93% Dividends declared on common shares and paid in cash 3 57,613 49,358 36,982 Payout Ratio - after the impact of the DRIP 77% 73% 63% 1. The portion of Free Cash Flow attributed to non-controlling interests is subtracted, regardless of whether or not an actual distribution to noncontrolling interests is made, in order to reflect the fact that such distributions may not occur in the period they are generated. 2. These amounts represent cash receipts by the Harrison Hydro L.P. for the wheeling services to be provided to the Big Silver, Tretheway Creek and Northwest Stave River facilities respectively, 49.99% of which was included in the Free Cash Flow attributed to non-controlling interests. 3. Represents dividends declared on common shares outstanding that were not registered in the DRIP at the time of the declaration; the dividends declared on common shares registered in the DRIP were paid in common shares. For the year ended December 31, 2015, the Corporation generated Free Cash Flow of $74.4 million, compared with $67.7 million for the same period last year. This increase is due mainly to higher adjusted EBITDA resulting in greater cash flows. The realized losses on derivative financial instruments were not financed from the operations but from the project-level financings put in place in During the year, the Corporation used $12.4 million of its Free Cash Flows to purchase for cancellation 1,190,173 common shares under its normal course issuer bid. Payout Ratio The Payout Ratio represents the dividends declared on common shares divided by Free Cash Flow. The Corporation believes it is a measure of its ability to sustain current dividends and dividend increases as well as its ability to fund its growth. For the year ended December 31, 2015, the dividends on common shares declared by the Corporation corresponded to 86% of Free Cash Flow, compared with 88% for the corresponding prior 12-month period. This positive change is due mainly to the increase in Free Cash Flow explained above, which more than offset the increase in dividends resulting from the higher number of common shares outstanding by virtue of the DRIP, the issuance of 4,027,051 common shares of the Corporation in June 2014 to pay for the acquisition of the SM-1 hydroelectric facility and the issuance of 3,653,422 common shares of the Corporation upon conversion, at the holders' request, of convertible debentures bearing interest at a rate of 5.75%. The Payout Ratio reflects the Corporation's decision to invest each year in advancing the development of its Prospective Projects, which investments must be expensed as incurred. The Corporation considers such investments essential to its longterm growth and success, as it believes that the greenfield development of renewable energy projects offers the greatest potential internal rates of return and represents the most efficient use of management's expertise and value-added skills. For the year ended December 31, 2015, the Corporation incurred prospective project expenses of $8.0 million, compared with $5.7 million for the corresponding prior period. This 41% increase is attributable mainly to the current request for proposals in Ontario, to the advancement of a number of prospective projects and to pursuing opportunities in new international markets. Innergex Renewable Energy Inc Financial Review - 42

44 MANAGEMENT'S DISCUSSION AND ANALYSIS Excluding these discretionary expenses, the Corporation's Payout Ratio would be approximately 8% points lower for the year ended December 31, 2015, and approximately 7% points lower for the corresponding prior period. Furthermore, the Corporation does not expect to require additional equity in order to complete its current four Development Projects, given the anticipated increase in cash flows from operations once these projects have been commissioned, the projectlevel financing that the Corporation has secured for these projects and the additional equity provided by the DRIP. PROJECTED FINANCIAL PERFORMANCE As at the date of this MD&A, the Corporation has 34 Operating Facilities with a net installed capacity of 708 MW (gross 1,216 MW) and annualized consolidated long-term average production of 3,130 GWh. The Corporation is also pursuing the construction of four Development Projects with power purchase agreements. Outlook for Power Generated (GWh) approx. +6-8% 2,988 +1% 2, % Revenues approx % 246,869 +2% 241, % Adjusted EBITDA approx. +7-9% 183,738 +2% 179, % Number of facilities in operation Net installed capacity (MW) Consolidated LTA production, annualized (GWh) 3,785 3,130 3,050 The increase in installed capacity and in the number of facilities in operation in 2016 reflects the expected commissioning of the Big Silver Creek hydroelectric facility and the Mesgi'g Ugju's'n wind farm project before year-end. Projected increases in production and revenues reflect production levels in line with the long-term average production. The increase in Adjusted EBITDA reflects a significant increase in expected Prospective Projects expenses, as the Corporation funds its expansion into target markets internationally. In 2015, Power Generated and Revenues were expected to increase 3-5% while lower-than LTA production resulted in a 1% and 2% respective increase. Although adjusted EBITDA was expected to increase by 1%, it actually increased by 2%, despite lower production, due to lower operating and administrative expenses than had been budgeted. OUTLOOK FOR 2017 The Corporation makes certain projections to provide readers with an indication of its business activities and operating performance once the four existing Development Projects have been commissioned. Please refer to the "Development Projects" section for more information on these projects. These projections do not take into account possible acquisitions, divestments or additional Development Projects following the award of any new power purchase agreements. Once the four Development Projects have been commissioned, the Corporation expects its annualized consolidated LTA production to increase from 3,130 GWh at the end of 2015 to 4,211 GWh starting in 2017, which corresponds to a 35% increase. Innergex Renewable Energy Inc Financial Review - 43

45 MANAGEMENT'S DISCUSSION AND ANALYSIS Projected Installed Capacity The Corporation believes that installed capacity provides a good indication of the size and magnitude of its operations. Once the four existing Development Projects have been commissioned, the Corporation expects its net installed capacity to increase from 708 MW (gross 1,216 MW) at the date of this MD&A to 895 MW (gross 1,513 MW) at the end of 2017, corresponding to a 26% increase (gross 24%). Net installed capacity reflects the fact that some of the Corporation's Operating Facilities are not wholly-owned. Installed capacity includes the Umbata Falls and Viger- Denonville facilities that are treated as joint ventures and accounted for using the equity method. Projected Long-Term Average Production (LTA) A key performance indicator for the Corporation is to compare actual electricity generation with the expected LTA production for each facility. Once the four existing Development Projects have been commissioned, the Corporation expects its annualized consolidated LTA production to increase from 3,130 GWh as at the date of this MD&A to 4,211 GWh starting in 2017, corresponding to a 35% increase. Consolidated LTA production is presented in accordance with revenue recognition accounting rules under IFRS and excludes the Umbata Falls and Viger-Denonville facilities that are treated as joint ventures and accounted for using the equity method Projected Adjusted EBITDA A key performance indicator for the Corporation is Adjusted EBITDA generation. Once the four Development Projects have been commissioned, the Corporation expects to generate annualized Adjusted EBITDA starting in 2017 of approximately $295.0 million (adjusted for an inflation component thereafter), compared with $183.7 million in This represents an annual compound growth rate of approximately 27% for the period. Adjusted EBITDA is presented in accordance with revenue recognition accounting rules under IFRS and excludes the Umbata Falls and Viger-Denonville facilities that are treated as joint ventures and accounted for using the equity method. The annual Adjusted EBITDA for these facilities combined attributable to the Corporation is approximately $8.0 million. Annualized Consolidated LTA Production As at the date of this MD&A Starting in 2017 Hydro 2, ,982.2 Wind ,191.5 Solar Total 3, , Solar farm LTA diminishes over time due to expected solar panel degradation Adjusted EBITDA ($M) It should be noted that Adjusted EBITDA does not take into account the impact of interest and principal payments on the Corporation's existing debt and on the project-level debt financing. Innergex Renewable Energy Inc Financial Review - 44

46 MANAGEMENT'S DISCUSSION AND ANALYSIS Projected Free Cash Flow Another key performance indicator for the Corporation is the Free Cash Flow generated from its operations and available for distribution to common shareholders and for reinvestment to fund its growth. Once the four existing Development Projects have been commissioned, the Corporation expects to generate Free Cash Flow in 2017 of approximately $105.0 million, compared with $74.4 million in This represents an annual compound growth rate of approximately 19% for the period and will reflect the cash flows generated by the Corporation's 38 Operating Facilities at that time, after taking into account maintenance capital expenditures, scheduled debt principal payments, preferred share dividends and the portion of Free Cash Flow attributed to non-controlling interests. For 2017, the increase in Free Cash Flow of $10.0 million ($105.0 million compared to $95.0 million), compared with the information published as at December 31, 2014, is due mainly to more favourable debt amortization schedules on the project-level debts that the Corporation has secured over the past several months. Free Cash Flow ($M) For more information on the principal assumptions used in determining projected financial information and the principal risks and uncertainties related thereto, please refer to the "Forward-Looking Information" section. Innergex Renewable Energy Inc Financial Review - 45